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November 27, 2024

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BANC Signs Agreement to Join EDAM

The Balancing Authority of Northern California (BANC) on Nov. 25 became the third entity to formally join CAISO’s Extended Day-Ahead Market (EDAM), following PacifiCorp and Portland General Electric (PGE).  

“BANC is pleased to execute the EDAM implementation agreement with the ISO,” BANC General Manager Jim Shetler said in a press release, adding that CAISO’s Western Energy Imbalance Market (WEIM) “has brought BANC and its members reliability, economic and environmental benefits.” 

“EDAM participation is viewed as the next logical step to expand on those benefits. We look forward to working with the ISO to achieve a spring 2027 go-live date,” Shetler said.  

Shetler has been a key participant on the West-Wide Governance Pathways Initiative’s Launch Committee, which on Nov. 22 passed its “Step 2” proposal to establish an independent “regional organization” to assume governance of the WEIM/EDAM, a move that will require a change in California law. (See Amid Praise for Pathways Step 2 Milestone, Skeptics Remain Unmoved and Pathways Backers Express Confidence on Calif. Legislation.)   

BANC is a joint powers authority consisting of six utilities: Sacramento Municipal Utility District (SMUD), Modesto Irrigation District, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake. It has been a WEIM member since 2019.   

In 2023, BANC was one of the first entities — along with its largest member, SMUD — to announce its intent to join the EDAM, after PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.) 

The formal commitment comes a month after the Western Area Power Administration (WAPA) said its Sierra Nevada (SN) region would pursue “final negotiations” to join the EDAM, clearing the way for BANC to formally join. (See WAPA Sierra Nevada Region to Advance with EDAM.) 

“We are excited to welcome BANC as the first public power balancing authority to formally commit to join EDAM,” CAISO CEO Elliot Mainzer said. “They have been a valued partner whose voice has been instrumental to the design of EDAM, and we look forward to having them join the market to deliver more benefits to their customers.” 

Along with formal commitments from BANC, PacifiCorp and PGE, three other entities have signaled their interest in joining EDAM: Los Angeles Department of Water and Power, BHE Montana and PNM. An additional two entities, Idaho Power and NV Energy, have indicated they favor EDAM.  

Arizona G&T Cooperatives, consisting of utilities that represent 70% of WAPA Desert Southwest’s load, also recently announced it will conduct a study on the benefits of joining EDAM. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)

The Pathways Initiative’s “Step 1” plan, which elevates the Western Energy Markets Governing Body to become the “primary” authority over the WEIM/EDAM compared with the “joint” authority it currently shares with the ISO’s Board of Governors, will be triggered once EDAM commitments from non-ISO load reach 70% of ISO load. BANC’s participation means EDAM has achieved commitment from 53% of non-ISO load compared with ISO load.  

BANC’s EDAM implementation agreement is slated to be filed with FERC in December.  

SPP’s competing Markets+ offering on Nov. 25 won its first public commitments from four Arizona utilities, although the RTO is still awaiting FERC approval for the market’s tariff and no implementation agreements have been signed. (See 4 Arizona Utilities Commit to Joining Markets+.)  

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NERC Responds to FERC Cybersecurity NOPRs

Replying to two recent cybersecurity-related Notices of Proposed Rulemaking from FERC, NERC and the regional entities Nov. 22 expressed their support for the proposals while urging the commission to “consider the entirety of” the ERO Enterprise’s standards development process when setting their deadlines. 

The NOPRs propose to expand the ERO’s recently introduced reliability standard requiring registered entities to implement internal network security monitoring (INSM) at some grid-connected cyber systems (RM24-7) and to address perceived gaps in the standards concerning supply chain risk management (RM24-4). The commission issued both NOPRs at its monthly open meeting Sept. 19. (See FERC Proposes Further Cybersecurity Measures.) 

Clarity Requested on INSM Expansion

The INSM proposal builds on CIP-015-1 (Cybersecurity — INSM), which FERC proposed to approve in the same NOPR. The standard requires utilities to implement INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity. 

While FERC said the standard would advance grid reliability, in its current form, it is “not … fully responsive to the commission’s directive” to implement INSM. In particular, the commission worried that attackers may be able to compromise systems external to an entity’s electronic security perimeter (ESP) and use that control to establish access within the perimeter as a trusted connection. 

It proposed directing NERC to modify the standard to include electronic access control and monitoring systems (EACMS) and physical access control systems (PACS) in the list of those requiring INSM, which it said would protect “all trust zones of the CIP-networked environment.” 

In its response, NERC first called on the commission to approve CIP-015-1 “as expeditiously as possible,” saying the standard would “improve the probability of detecting anomalous or unauthorized network activity” and help utilities respond to cyberattacks. But, the ERO continued, FERC needs to provide additional clarity on what it means by the term “CIP-networked environment.”  

Although NERC acknowledged that FERC said in the NOPR that the term includes “all assets and systems to which the CIP [critical infrastructure protection] standards apply and [that] may be the targets of attacks,” the ERO pointed out that the term is still not explicitly defined in the proposal. 

“To facilitate an expeditious development process, it would be beneficial if the commission clarifies in a final rule the expected scope of any internal network security monitoring revisions,” NERC said. “For example, in extending the CIP-015-1 protections to EACMS and PACS, would the term ‘CIP-networked environment’ be restricted to east-west communications between EACMS and PACS outside of the ESP? Similarly, would the communications between PACS and controllers and communications to and from EACMS used solely for electronic access monitoring be included?” 

NERC also suggested that FERC give the ERO at least 12 months to complete the proposed revisions, in light of the ERO’s growing standards development workload. NERC pointed out that it is already resolving 82 outstanding FERC directives through the standards development process, and its seven “high priority” projects alone are expected to take more than 10,000 total drafting team hours to complete by the end of 2025. 

Noting that FERC proposed to require that the CIP-015-1 revisions be submitted within 12 months of the final rule, NERC urged the commission to give it enough time to “facilitate additional development options,” including a technical conference, while also allowing the ERO to “balance limited resources between competing high priority projects.” 

ERO Supports Supply Chain Proposal

In the second NOPR issued Sept. 19, FERC indicated its intent to direct NERC to develop new or modified standards regarding evaluation of vendors and equipment to identify supply chain risks, along with processes to validate the accuracy of information received from vendors during procurement and track supply chain risks. 

The commission said it felt moved to act because of “multiple gaps” in NERC’s existing supply chain risk management (SCRM) standards: 

    • CIP-005-7 — Cybersecurity — electronic security perimeter(s);  
    • CIP-010-4 — Cybersecurity — configuration change management and vulnerability assessments; and  
    • CIP-013-2 — Cybersecurity — supply chain risk management. 

FERC said the standards do not specify when and how entities should identify and assess supply chain risks, and do not require entities to respond to supply chain risks through their SCRM plans. 

In their response, NERC and the REs said they appreciate FERC for recognizing the work they have done so far to advance SCRM, including their efforts to revise CIP-013-2 (which were cut short when FERC announced it would be addressing SCRM at the September meeting).  

They said they support the proposed revisions, including adding protected cyber assets (defined by NERC as “cyber assets connected … within or on an [ESP] that is not part of the highest impact … cyber system within the same [ESP]”) as applicable assets within supply chain requirements. However, as with the other NOPR, the ERO Enterprise reminded the commission of its standard development workload and the other deadlines to which it is subject. 

The organizations also asked FERC to consider the relationship between the different standards. Some standards refer to others, and revisions to CIP-005-7, CIP-010-4 and CIP-013-2 could impact other ongoing standards development projects. For example, earlier in 2024, NERC filed a suite of proposed changes to nearly all of the CIP standards, including the three supply chain standards, which might affect the team tasked with carrying out FERC’s order. (See NERC Sends Virtualization Standards to FERC.) 

NERC and the REs requested that FERC “consider no less time than proposed in the NOPR” — 12 months — to both accommodate the busy standards development pipeline and “provide the standards drafting team certainty on the version of CIP reliability standards to revise.” 

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Developers Seek Deadline Extension in NJ Storage Plan

Solar developers are urging the New Jersey Board of Public Utilities to extend the completion timelines in the agency’s proposed storage development plan, saying that 550 days to complete a project and secure connection through PJM is too short.

The board’s draft proposal requires grid supply or distributed projects approved under the program to be commercially operating within 550 days of getting the agency award. If they are not, “the capacity they reserved would be returned to the market” and be available for other projects, the proposal says.

The timeline was the most salient concern at a Nov. 20 hearing, in which other speakers — while generally supporting the proposal — called for the BPU to address a range of issues, among them accelerating the start of the program segment focused on distributed storage and strengthening it to make it more attractive to developers.

The proposal, the New Jersey Storage Incentive Program (NJ SIP), sets out the guidelines for two sectors: a program for behind-the-meter, distributed projects that is expected to launch in 2026 and one for in-front-of-the-meter projects, including grid supply projects, that will begin in early 2025.

At least six of the more than two dozen speakers said they believe the project completion deadline — known as a maturity requirement — is too restrictive.

Dan Watson, director of development at Jupiter Power, a large-scale energy storage developer, said construction alone can take three years on a large project.

“It can be a long time with the PJM related upgrades as well,” he said. “So, the 550-day timeline is in obvious need of correction and consideration for larger projects.”

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said a grid supply project in front of the meter would “be applying as a wholesale generator in order to do a front-of-the-meter project,” and the current proposed timeline would be tough to meet.

“That’s a process that could take as long as two years or more,” he said. “I know you want to get started on that program in 2025. But it’s unlikely that we can even get approvals until 2027.”

PJM is working through a major backlog of resources and not accepting any new project requests until 2026.

The proposal says the intention of the requirements “is to eliminate projects that cannot be expected to reach commercial operation within a reasonable time frame.” The proposal explains that a project is considered to have reached commercial operation if “it is fully constructed and has completed the full interconnection process, either at PJM or with a New Jersey jurisdictional [electric delivery company], including construction of any required interconnection upgrades.”

A BPU representative at the meeting said the BPU’s consultant on the project suggested the 550-day timeline. He added that several speakers expressing concern about the requirements “gets our attention,” and the BPU staff would consider the issue.

Launch Date Controversy

The NJ SIP proposal is a revised version of a draft proposal first released in September 2022, with changes made in response to stakeholder input. The state aims to install 2,000 MW of total capacity by 2030, but progress has been slow. A BPU spokesperson said the state currently has 560 MW of installed storage, but that capacity will not be counted toward the 2,000-MW goal.

Several speakers said there is significant interest in developing storage in the state. Diane Cherry, deputy director of the Mid-Atlantic Renewable Energy Coalition, said there are 3,700 MW of storage projects in the PJM queue. Noting the state’s 2,000-MW goal, she urged the BPU to focus on grid-supply project incentives and said, “we can easily meet and exceed this goal with the appropriate regulatory direction.”

Joshua Lewin, president of Helios Solar Energy of Somerville, N.J., encouraged the board to consider launching both the distributed and grid supply segments in 2025, rather than delay the distributed project launch by a year — an opinion also voiced by other speakers.

“This continued delay in the program rollout is unhelpful in gaining customer willingness to enter a new and unfamiliar market,” he said.

The revised NJ SIP includes a competitive solicitation to determine the incentive level for grid supply projects, which was not in the original plan. Also new is an option under which the BPU will accept applications from solar-plus-storage projects, rather than standalone storage projects. That will allow the program to accept projects that are not eligible to receive storage incentives from the Competitive Solar Incentive part of the Successor Solar Incentive program, which encompasses solar-plus-storage projects. (See NJ BPU Updates Proposal for Storage Incentives.)

The revised proposal also makes the bid-participation fee of $1,000/MW refundable to unsuccessful bidders, instead of nonrefundable. BPU said the shift stems from the addition to the plan of a “pre-development security” of up to $100,000/MW, to be paid upon application approval.

The security is designed to ensure the project is carried out as planned, allowing the BPU to impose penalties that will be deducted from the security if the project misses the Planned Commercial Operation Date or the Guaranteed Commercial Operation Date.

The storage proposal also has deferred implementation of a distributed pay-for-performance incentive on projects to give utilities time to develop the mechanism to calculate it.

Prioritizing Segments

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, urged the BPU to focus the program resources on distributed storage rather than grid-scale storage projects. He said the association’s recent member survey showed many already are engaged in the sector.

“There’s a lot of development going on anywhere from less than 10 KWh to tens of megawatt hours in the behind-the-meter storage field,” he said. One reason, he said, is that “behind-the-meter revenue is substantially more than the grid supply revenue.”

“Behind-the-meter storage is going to be for the foreseeable future more economic, and that means long term a better ability to reduce the incentives from the program and save ratepayers money,” he said. Other speakers said distributed projects, because they are smaller, may get up and running and contribute to the state’s need for storage more quickly.

Addressing the ratepayer impact, Megan Lupo, assistant deputy ratepayer advocate for the New Jersey Division of Rate Counsel, took issue with a new element in the proposal that directs the BPU to pay developers or owners the full project incentive upfront, rather than over 10 to 15 years.

She said the board staff concluded the new system would reduce the level of risk and so bolster program incentives.

“However, it is not clear that any additional incentives are needed for New Jersey to achieve its statewide goals,” she said. “An increase in incentives should be supported by evidence that proves the current incentives are insufficient to meet statewide targets. If not, New Jersey risks over-incentivizing energy storage.”

Lupo also expressed concern about making the fees refundable.

“This change would risk making the bidding process less meaningful and may cause an increase in the number of bids that are speculative in nature,” she said, adding that $1,000/MWh is low compared to other states.

“There is no reason to believe these current nonrefundable fees are overly burdensome to bidders,” she said.

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LPO Announces $4.9B Conditional Loan for Invenergy’s Grain Belt Express

With less than two months until President-elect Donald Trump takes office, the Department of Energy’s Loan Programs Office on Nov. 25 announced three conditional loans totaling more than $11 billion, to be used to build interregional transmission, an electric vehicle factory and virtual power plants.  

Invenergy’s Grain Belt Express, an interregional high-voltage direct current line, has received a conditional loan of $4.9 billion to help finance Phase 1 of the project, a 578-mile, 2,500-MW line running from Ford County, Kansas, to Callaway County, Missouri, according to the LPO announcement.  

The second phase of the project, from Missouri to Illinois, eventually will take the HVDC line to 800 miles and connect SPP, Associated Electric Cooperative, MISO and PJM. The LPO announcement notes that DOE’s National Transmission Needs Study has estimated that interregional transfer capabilities between SPP and MISO might need to increase tenfold by 2035 to meet growing power demand. 

EV maker Rivian is slated for up to $6.57 billion for the development and construction of a new plant east of Atlanta. The company plans to build out the facility in two phases, with production of its R2 and R3 SUVs beginning in 2028 and eventually ramping up to 400,000 vehicles per year, according to a Nov. 25 press release.  

If finalized, the Rivian loan would be the first made under LPO’s Advanced Technology Vehicles Manufacturing (ATVM) Loan Program to manufacture EVs in the U.S., as opposed to EV components, LPO said.  

A third conditional loan, for $289.7 million, will go to Sunwealth, a commercial solar developer, which will use the money to install up to 1,000 solar and storage systems across as many as 27 states. The projects will include installations on commercial and multifamily buildings, as well as community solar facilities.  

Partnering with SYSO, a developer of distributed energy resources management systems, Sunwealth intends to aggregate the systems as a virtual power plant. Estimated capacity of the systems could total up to 168 MW of solar and 16.8 MW and 33.6 MWh of battery energy storage, according to LPO. 

The announcements of the conditional loans signal the start of contract negotiations between LPO and the potential recipients to finalize the awards. Companies must “satisfy certain technical, legal, environmental and financial conditions before [LPO] enters into definitive financing documents and funds the loan,” the announcements all say. 

These negotiations often take months, which could mean uncertainty for the awardees. Prior to his election, Trump pledged to claw back any unspent dollars from the Inflation Reduction Act, which added billions to the funds available to LPO. Some analysts have predicted a Day 1 executive order halting any further distribution of IRA funds.  

In response to questions from RTO Insider, an LPO spokesperson did not comment on whether the office would be able to finalize the contracts for these three conditional loans before Trump takes office, focusing instead on the office’s role as a “bridge to bankability” for a broad range of greenhouse gas-reducing technologies.  

Since President Joe Biden took office in 2021, LPO has announced 31 deals totaling approximately $47.72 billion in project investment, including 13 projects with finalized contracts for $13.18 billion in federal support. Contracts for 18 projects totaling $34.54 billion are pending, according to the spokesperson. 

“Utilizing funding provided by Congress, LPO has accomplished tremendous progress in a short amount of time on bipartisan priorities including advanced nuclear, geothermal, advanced fossil energy and critical minerals,” the spokesperson wrote in an email. “As a result, there is steel in the ground and job openings at new or expanded facilities around the country.  

“It would be irresponsible for any government to turn its back on private-sector partners, states and communities that are benefiting from lower energy costs and new economic opportunities spurred by LPO’s investments.” 

Navigating Uncertainty

Both Invenergy and Rivian welcomed the LPO announcements, while still navigating ongoing uncertainties about their respective projects. 

In an emailed statement, Shashank Sane, executive vice president and head of transmission at Invenergy, said, “We are pleased to see LPO’s evaluation validate the findings of the Kansas and Missouri public utility commissions, both of which have long affirmed our project is key to improving grid affordability and reliability across the Heartland.”  

The first phase of the project has earned successive approvals from the Kansas Corporation Commission, originally in 2019 and again in 2023 to increase capacity for power delivery on the line, according to the project website. The Missouri Public Service Commission issued similar approvals in 2019 and 2022. 

However, Invenergy has run up against interconnection delays in MISO, which has given the project a 2030 interconnection date, versus the project’s original target of a 2027 in-service date. In February 2024, FERC approved an interconnection agreement with the 2030 date.  

Invenergy had asked MISO for a limited operation provision in the agreement to allow the Grain Belt Express to begin partial operations in 2027. (See FERC OKs Grain Belt Express Connection Agreement with MISO; Invenergy Displeased with 2030 Target.)

FERC also gave Invenergy only partial approval to charge negotiated rates on the line once in operation. (See Grain Belt Express Gets Partial Approval for Negotiated Rate Authority from FERC.) 

Rivian founder and CEO RJ Scaringe said the LPO’s loan, if finalized, “would enable Rivian to more aggressively scale our U.S. manufacturing footprint. … A robust ecosystem of U.S. companies developing and manufacturing EVs is critical for the U.S. to maintain its long-term leadership in transportation.” 

Rivian suspended work on the new plant in Georgia in March, shifting production of its R2 SUV to its plant in Illinois, a decision saving the company $2.25 billion, according to a press release. 

The company has not specified when it will resume work on the plant, but according to a spokesperson, “Georgia will provide the volume of production essential for us to enter new markets, including international ones. We expect to start construction to meet our stated goal of start of production in 2028.” 

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State Briefs

FLORIDA 

PSC Staff: FPL Should Charge Customers for Storm Costs

Public Service Commission staff last week recommended that Florida Power & Light should be allowed to make up about $1.2 billion by temporarily charging an add-on to customers’ bills to cover costs related to hurricanes Debby, Helene and Milton. 

Under FPL’s proposal, average customers would see their monthly bills go from $121.19 a month to $133.99 in January 2025. 

The PSC is scheduled to take up the request Dec. 3. 

More: WFOR 

MAINE 

Portland City Council Votes to Establish Climate Action Fund

The Portland City Council unanimously voted to establish a municipal climate action fund, which was recommended by city staff and the council’s finance and sustainability and transportation committees. 

The ordinance establishing the fund allows spending both on initiatives to “advance strategies in One Climate Future” and to fund costs of operating the sustainability office including “staff salaries, interns, public outreach and engagement, professional development, software licenses or subscriptions.” One Climate Future is a shared climate action plan for the cities of Portland and South Portland that lays out a plan for reducing contributions to climate change. 

The council later approved a spending cap of $125,000 for staff salaries. 

More: Portland Press Herald 

MARYLAND 

BPW Approves Permit to Expand Pier for OSW Development

The Board of Public Works last week unanimously approved a permit to expand the 353-foot Sinepuxent Bay pier in West Ocean City that will support US Wind’s plan to build its offshore wind project. 

The pier is currently used by local fishers. 

US Wind plans to build a 114-turbine, 2-GW wind farm 8 miles off the coast of Ocean City. 

More: Maryland Matters 

Climate Commission Tables Debate on Revenue-generating Measures

The Commission on Climate Change last week delayed a decision on adopting aggressive revenue-generating measures to fund programs that confront climate change until next month. 

The commission is putting the finishing touches on its annual list of recommendations for Gov. Wes Moore and lawmakers to consider for the state’s ongoing attempts to meet climate mandates. The report includes recommendations that the state authorize a cap-and-invest scheme to make the transportation and building sectors pay for carbon emissions, establish a fossil fuel transport fee and mitigation fund, and make large fossil fuel companies compensate the state for climate emissions and associated environmental degradation. 

The document is scheduled to be finalized Dec. 12. 

More: Maryland Matters 

MICHIGAN 

Municipalities Challenge State’s New Clean Energy Zoning Law

In a claim filed with the Court of Appeals, 72 townships and seven counties argued against a new state law that places the permitting for renewable energy projects under the control of the Public Service Commission. 

Opponents of the law have argued that it takes the permitting process away from local governments and violates the Administrative Procedures Act, which dictates the rulemaking process for state agencies, among other things. 

While the law requires energy companies to work with localities whose permitting process matches the state’s, utilities can submit a permitting application to the PSC for several reasons, including the impacted community failing to approve or deny an application in a timely manner. 

More: Michigan Advance 

MINNESOTA 

Phase 1 of Sherco Solar Plant Completed

Xcel Energy last week announced its Sherco Solar plant has completed Phase 1 of its three-phase development. 

The facility now generates 220 MW and consists of 500,000 panels but is expected to triple to 1.5 million panels by 2026. 

More: WCCO, KSTP 

NEW HAMPSHIRE

PUC Leaves Net Metering Rules Unchanged, Will End in 2040

As order from the Public Utilities Commission made no substantive changes to the state’s net metering program. 

Most notably, the order does not extend the termination date of the program that was established in a 2017 PUC order, which will be at the end of 2040. However, the PUC said it will “establish further process to consider additional changes to the net-metering tariff as part of the commission’s ongoing obligation to develop and improve net-metering tariffs in New Hampshire.” In a supplemental order, it set a February 2025 meeting to start the process. 

More: Concord Monitor 

NEW JERSEY

BPU Approves Gas Rate Hikes

The Board of Public Utilities last week approved rate increases for New Jersey Natural Gas and Elizabethtown Gas. 

The average New Jersey Natural Gas customer can expect to see their bill rise by $23.94 (15.8%) per month. Elizabethtown Gas Company customers will see a monthly increase of $9.43 (6.5%). 

Board officials lamented the increases but said they are necessary to fund infrastructure upgrades to prevent gas leaks and other problems. 

More: New Jersey Monitor 

NORTH CAROLINA

Duke to Retire Gaston County Coal Plant, Replace with Battery Storage

Duke Energy plans to shutter and demolish its Allen coal-fired plant and replace it with battery storage. 

Duke said it will initially build two arrays of batteries on the site to store electricity from other plants, primarily nuclear and solar energy. The first set of 50-MW batteries will open by the end of 2025. The second set of 167 MW is expected to be ready in October 2027. 

Duke has been shutting Allen’s five coal-burning units gradually since 2021. The final unit will close at the end of 2024. 

More: WFAE 

NORTH DAKOTA

PSC Approves $440M Tx Line

The Public Service Commission last week voted 2-1 to approve a $440 million, 85-mile transmission line that will be paid for in part by Otter Tail Power and Montana-Dakota Utilities customers. 

With the approval of the 345-kV line, MDU customers will pay an additional 12.3 cents/month and Otter Tail customers about 17.7 cents/month.  

More: North Dakota Monitor 

OREGON 

EQC Approves Redo of Climate Program After Lawsuit Derailed It

The Environmental Quality Commission last week voted unanimously to approve a program that sets emission targets and will serve as a foundation for the state’s drive to reduce greenhouse emissions. 

The vote came 11 months after a court invalidated the original 2021 program. NW Natural, Avista and Cascade Natural Gas sued to block the plan in 2023, saying in the process of imposing state regulations to cap and reduce emissions, the commission failed to submit required disclosures to the companies. 

Little changed from the original standards, with the mandated targets for reducing greenhouse gas pollution remaining at a 50% reduction by 2035 and a 90% reduction by 2050. 

More: Oregon Capital Chronicle 

SOUTH CAROLINA

Final Executive Punished for VC Summer Failure

U.S. District Judge Mary Geiger Lewis last week sentenced Jeff Benjamin, a top executive for Westinghouse Electric, to 10 months in prison and a fine of $100,000 for his role in the failure of the V.C. Summer Nuclear Plant. 

Benjamin pleaded guilty in December to aiding and abetting the failure to keep accurate corporate records. Benjamin admitted to telling presidents of the now-defunct SCANA that the plan to build two nuclear reactors was still on track, despite the subcontractor his company had hired saying there was no way they would be done in time. 

Westinghouse eventually told SCANA and state-owned Santee Cooper, the utilities that jointly hired the company to build the two reactors, in 2017 that the company was facing a $6.1 billion loss from the project. The utilities then abandoned the project, but not before spending $9 billion. 

More: South Carolina Daily Gazette 

SOUTH DAKOTA

Summit Carbon Solutions Reapplies for Permit

Summit Carbon Solutions last week resubmitted a permit application for its proposed carbon dioxide pipeline to the Public Utilities Commission. 

The move comes more than a year after the PUC rejected the company’s initial application and said the route was non-compliant with county laws mandating minimum distances between pipelines and existing features. Summit’s latest route includes 700 miles with connections to 14 ethanol plants, plus a proposed sustainable aviation fuel plant. Overall, the $9 billion pipeline would span 2,500 miles with connections to 57 ethanol plants in five states.  

Summit already has permits in Iowa and North Dakota. A decision is pending in Minnesota, while Nebraska has no state permitting processing for carbon pipelines. 

More: South Dakota Searchlight 

VIRGINIA 

Dominion Halts Pumped Storage Station Development

Dominion Energy last week announced it will not proceed with the proposed $2 billion Tazewell Pumped Storage Facility in Tazewell County. 

Dominion said it stopped development due to “the cost impact to our customers, the expiration of a FERC permit and the availability of more affordable and higher-capacity generation options.” 

More: Bluefield Daily Telegraph 

Dominion Requests Rate Hikes to Cover OSW, SMR Costs

Dominion Energy recently filed requests with the State Corporation Commission to raise rates to cover the expenses associated with its offshore wind farm and early development of small modular nuclear reactors. 

The request would charge average residential customers an additional $2.89 a month. 

The SCC must review and approve the proposals, which are planned to take effect on Sept. 1, 2025. 

More: VPM 

Judge Deems Gov. Youngkin’s Actions to Withdraw State from RGGI ‘Unlawful’

Floyd County Circuit Court Judge Randall Lowe last week ruled Gov. Glenn Youngkin acted unlawfully by withdrawing the state from the Regional Greenhouse Gas Initiative. 

In his opinion, Lowe wrote that “the only body with the authority to repeal the RGGI regulation would be the General Assembly. This is because a statute, the RGGI Act, requires the RGGI regulation to exist. For the reasons set out in this opinion, the court finds that the attempted repeal of the RGGI regulation is unlawful, and thereby null and void.” 

The Youngkin administration has said it will appeal the decision. 

More: Virginia Mercury 

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Federal Briefs

Biden Nominates 2 to TVA Board

President Joe Biden last week announced his intent to nominate Beth Harwell and Brian Noland to the Tennessee Valley Authority’s board of directors. 

Harwell has been serving as a member of the TVA board since 2021. 

Noland, the president of East Tennessee State University, has served as a board member for the American Council on Education, the American Association of State Colleges and Universities, the NCAA Division I Board of Directors, Ballad Health, Bank of Tennessee and the TVA. 

More: The White House 

Electrical Failures Knocked All TVA Nuclear Plants Offline in 2024

Electrical equipment failures temporarily knocked out all three of the Tennessee Valley Authority’s nuclear power plants in 2024. 

The equipment failures at the Sequoyah, Browns Ferry and Watts Bar nuclear plants led to what TVA classifies as forced outages, meaning operators cannot plan more than 10 days in advance for a unit to go offline. One forced outage included the failure of a main generator at Sequoyah that will cost $82 million to replace and will not be online again until 2025. 

TVA plans to submit license renewal applications for each of its nuclear plants. 

More: Knoxville News Sentinel 

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Company Briefs

GE Vernova Fires Workers Following Blade Failure Probe

GE Vernova confirmed it has fired a number of personnel from its LM Wind Power factory in Gaspé, Canada, following its investigation into a July blade failure at the 806-MW Vineyard Wind array. 

A GE spokesperson said the company “commenced an extensive internal review of our blade manufacturing and quality assurance program across our offshore wind operations following the July blade event at Vineyard Wind. During the review, we determined that the quality controls in our Gaspé factory did not meet our expectations. As a result, several weeks ago we implemented corrective actions at our blade facility in Gaspé, which included impacts to processes and people.” 

The company added that a “small number” of employees, including some senior level plant supervisors, were terminated or suspended because of the findings.  

More: Renews 

US Army Corps Approves Eco Wave Power Permit for Onshore Wave System

Eco Wave Power secured the final permit from the U.S. Army Corps of Engineers to install its first onshore wave energy system in the U.S. at the Port of Los Angeles. 

The permit allows Eco Wave Power to install eight wave energy floaters on the existing concrete wharf at Municipal Pier One. The setup will include an energy conversion unit housed in two 20-foot shipping containers. The floaters will convert the rising and falling motion of the waves into energy. 

Eco Wave Power plans to complete the installation in early 2025. 

More: Electrek 

NRG Energy, Renew Home Select Texas for 1-GW VPP

Renew Home and NRG Energy announced their intention to create a 1-GW virtual power plant in Texas by 2035, which would be the biggest in the country. 

Under the new program, set to launch in 2025, Renew Home and NRG are hoping to offer no-cost installations of Nest and Vivint smart thermostats. To get a free thermostat, customers must choose from a variety of rate plans and incentives that allow the companies to shift their power use. Renew Home estimates that 8.5 million homes could yield 8.5 GW of ​“load-shift potential” for ERCOT. 

Renew Home was formed last year by the merger of Google Nest’s smart-thermostat energy-shifting service Nest Renew and Ohmconnect, a startup with hundreds of thousands of residential demand-response customers. 

More: Canary Media 

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4 Arizona Utilities Commit to Joining Markets+

Four Arizona utilities announced their plans to join SPP’s Markets+ day-ahead market, a significant win for SPP after a string of victories for CAISO’s competing Extended Day-Ahead Market (EDAM). 

Arizona Public Service (APS), Salt River Project (SRP), Tucson Electric Power (TEP) and UniSource Energy Services made the announcement Nov. 25. 

Markets+ is expected to save the utilities nearly $100 million while enhancing reliability and supporting the addition of renewable resources to the grid, the utilities said in a joint release. 

The utilities said they plan to begin Markets+ participation as soon as 2027. 

“Together with our neighboring utilities, APS plans to join Markets+ to efficiently deliver energy and bolster the resilience of our shared energy grid in Arizona and across the region,” Brian Cole, APS vice president of resource management, said in a statement. 

When asked about the reasons for choosing Markets+ rather than CAISO’s EDAM, an SRP spokesperson said the primary drivers are governance and resource adequacy.   

The Markets+ governance structure promotes independence, transparency, inclusivity and stakeholder-driven decision-making, the spokesperson said.  

And Markets+ will adhere to a single, shared resource adequacy program — the Western Resource Adequacy Program — providing a consistent method to make sure enough resources are available to reliably serve load across the Markets+ footprint. 

“It also ensures that all market participants contribute fairly to the reliability of the market footprint, preventing any participants from systemically leaning on others,” the SRP spokesperson said. 

SRP expects a critical mass of entities joining Markets+ in spring 2027, and SRP will sign an implementation agreement before the market goes live. 

Tariff Decision Pending

The announcement comes as SPP awaits FERC’s decision on the Markets+ tariff, which initially was filed in March. FERC issued a deficiency letter in July identifying 16 problems in the tariff. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.) 

SPP filed a response to the letter in September, addressing each issue and asking FERC to issue an order by Nov. 20.  

But FERC isn’t required to abide by that request and will take “as much time as they need,” an SPP spokesperson told RTO Insider. SPP said previously it’s confident it can address concerns the deficiency letter raised. 

In contrast, CAISO’s EDAM already has received FERC approval. 

A TEP spokesperson said the company fully expects FERC to approve the Markets+ tariff, while acknowledging the approval can be an “iterative process,” a comment echoed by SRP. 

“We will continue to work with FERC and SPP throughout the process in demonstrating the value this direction will bring to our customers,” the TEP spokesperson said. 

FERC approval of the tariff will mark the start of a second phase of Markets+ development. 

“SPP thanks all Markets+ stakeholders for their engagement and collaboration in phase one development and looks forward to their continued involvement,” Antoine Lucas, SPP vice president of markets, said in a statement provided to RTO Insider. “We eagerly anticipate receiving signed phase two commitments by the end of the year so we can continue to work together to build a market that provides benefits for all western entities.” 

Footprints Taking Shape

The Arizona utilities’ announcement of their Markets+ decision is the latest step in the evolution of two day-ahead market footprints in the West. In addition to the Arizona announcement, Bonneville Power Administration has expressed a “leaning” toward Markets+ over CAISO’s EDAM. BPA is waiting for FERC’s ruling on the Markets+ tariff before deciding. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.) 

Although Powerex has not yet made a formal commitment to a day-ahead market, it has clearly signaled an intention to join Markets+ and to not join EDAM. 

The Arizona announcement “is a clear indication of the value that many utilities are seeing in the Markets+ day-ahead market option,” Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), said in an email to RTO Insider. 

The Portland-based PPC, a trade group representing the extensive network of Northwest publicly owned utilities that buy low-cost power from the Bonneville Power Administration, has been a consistent advocate of BPA choosing Markets+ over CAISO’s EDAM. (See Northwest Public Power Group Endorses Markets+ over EDAM.) 

“As a participant in the development of Markets+, PPC has appreciated the collaboration we have had with these Arizona utilities and the shared goals we have for a well-designed, well-governed day ahead market option,” Tenney Denison said. 

Meanwhile, EDAM scored its latest win this month with Public Service Company of New Mexico’s announcement of its plans to join the CAISO market. (See PNM Picks CAISO’s EDAM.) 

PacifiCorp, Portland General Electric and Balancing Authority of Northern California have signed EDAM implementation agreements with CAISO and the list of entities expected to join EDAM has grown to include NV Energy, Idaho Power and Los Angeles Department of Water and Power.  

In October, the Western Area Power Administration’s Desert Southwest (DSW) Region said it would cooperate with Arizona G&T Cooperatives on a study examining the potential benefits of DSW joining EDAM. DSW this year withdrew from the second phase of developing Markets+ after determining it would realize few benefits from participating in that market. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)    

After NV Energy announced its intent in May to join EDAM, Advanced Energy United issued a statement encouraging other entities, especially those in the Southwest, to join EDAM. The industry association said EDAM was becoming “the most viable day-ahead market.” 

Brian Turner, who leads Advanced Energy United’s regulatory engagement in the West, said AEU is pleased that Arizona utilities are “embracing broader energy markets,” which have the potential to bring customer benefits including greater reliability and affordability. 

But Turner said the Arizona announcement is “bittersweet,” as having two Western day-ahead markets will create seams and market inefficiencies.  

As the market footprints are now developing, Markets+ could end up with a “big fat seam” in Northwest-Southwest trade caused by NV Energy and California entities joining EDAM, Turner said in an interview. 

And the Arizona utilities are giving up known benefits of their participation in CAISO’s Western Energy Imbalance Market (WEIM) in exchange for unknown potential benefits of Markets+, he added. 

But how the Western day-ahead markets ultimately take shape remains to be seen. 

“Things are still very dynamic,” Turner said. 

Robert Mullin contributed to this article. 

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ERCOT Technical Advisory Committee Briefs: Nov. 20, 2024

Members Endorse 2 Changes to Transmission Planning

ERCOT stakeholders approved a pair of protocol changes related to transmission planning as the Texas grid operator continues to grapple with connecting incoming load to its system.

During the Technical Advisory Committee’s Nov. 20 meeting, members approved NPRR1247, which uses a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. They also approved NPRR1180 and a related change to the Planning Guide (PGRR107) that incorporates a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecasted load growth and additional load seeking interconnection.

Several generators and retailers opposed the first protocol change, noting that congestion costs can be hedged but transmission costs can’t.

“We think basing decisions on that is probably discounting a significant value that accrues to loads,” Luminant’s Ned Bonskowski said.

The NPRR was brought forward by ERCOT staff after collaborating with the Public Utility Commission. The ISO retained Energy and Environmental Economics (E3) to identify a set of viable options and provide recommendations for the most suitable congestion cost savings test. E3 presented its work in a March 2024 analysis, recommending a system-wide energy cost reduction test as the most suitable for ERCOT.

While staff approved E3’s recommendations, Luminant said the proposed congestion cost savings test could increase costs for ratepayers when competitive market solutions could serve load less expensively. The generator suggested applying a .25 multiplier factor to the calculated system-wide consumer energy cost reduction before using it to determine a project’s economic benefits.

“We think this may be a good compromise,” Bonskowski said. “If there’s a need to move forward on something today, we certainly would also support tabling” to give stakeholders more time to “make sure that we get this right before sending it up to the board.”

The vote to table NPRR1247 fell short, 11-17, with one abstention.

Mark Bruce, speaking for Pattern Energy, said his client is concerned about an overall lack of transparency and the need for further vetting. He said Luminant lacked backing data in its comments and urged stakeholders to revisit the matter with a change to the Planning Guide to further prevent downstream effects.

“I know there’s been some pressure from above to deliver something to the board on this at their next meeting,” Bruce said. “My client’s been engaged from the get-go, from its first showing as a draft before it was even filed. We’ve been trying to understand and perfect this very important revision request.”

TAC eventually approved the measure 25-3, with one abstention. Luminant, Calpine and Shell North America all opposed the motion.

The committee approved NPRR1180 25-0, with four abstentions, two from consumer interests.

The Office of Public Utility Counsel’s Nabaraj Pokharel said he supported the rule’s legislative intent but stressed the importance of ensuring load projections used for planning “are as accurate as possible.”

“There is a risk of unintended consequences, particularly if load studies are not thorough or accurate,” he said. “While building transmission to meet actual load is necessary, [it] could result in unnecessary cost that would ultimately be borne by residential consumers.”

To remedy that concern, Mark Dreyfus, speaking for a coalition of cities, suggested approving the protocol change and filing a follow-up revision request that drills down into the load-projection’s validation process.

“There’s a lot of projects waiting to have this process in place and we need to get moving on those projects,” he said.

Texas Competitive Power Advocates Executive Director Michele Richmond said several meetings with Oncor and other wires companies have resulted in a draft proposal for another NPRR that would address the process’ transparency and standardization.

“I think we are very comfortable with moving this forward, given that commitment and the really good discussions that we have been having,” Richmond said.

Large Loads Need a Segment Home

TAC discussed with staff potential changes to the committee’s segment makeup, driven by the growing influence of data centers and cryptocurrency miners that don’t fit neatly into either the industrial consumer or large commercial segments.

ERCOT membership has risen from 257 members in 2021 to 356 this year, mostly because of large flexible loads. Staff has asked entities with large loads to register in the industrial segment when making their membership applications for 2025.

The grid operator’s seven segments are used to fill out the 30-person TAC. Any changes to the representation would require an amendment to the bylaws and PUC approval.

“Things have changed a lot,” Engie’s Bob Helton said, alluding to a TAC segmentation that has been static since 2014. “Every time we talk about this, we have to be careful of balance. Anything we do is going to be a long, drawn-out deal to make sure that that balance remains in place and that no segment or group has a heavier weight than any other one in trying to approve things.”

Staff said ERCOT now has just over 62 GW of large loads in its interconnection queue. It has added another gig of new standalone and co-located projects since October.

West Texas Project Endorsed

TAC members endorsed ERCOT’s recommended $202.2 million Oncor project that addresses reliability issues in West Texas, placing it on the combination ballot.

The project stems from the 2019 Delaware Basin Load Integration Study. The region has significant oil and natural gas load and ERCOT’s highest peak demand growth rate percentage in recent years.

The Regional Planning Group approved Oncor plans to upgrade an existing capacitor station, build 22 miles of double-circuit 345-kV lines, convert 41 miles of 138-kV lines to 345-kV, build 41 miles of new 138-kV lines, and install six 5000-A, 345-kV circuit breakers. The project is expected to be completed in 2027.

Because the project cost more than $100 million, making it a Tier 1 project, it must be approved by ERCOT’s Board of Directors.

Co-chair Martin to Step Away

The meeting was the last as TAC’s co-chair for Collin Martin, Oncor vice president of grid operations. Martin told his fellow members he is stepping away “partially” to focus on potential transmission projects in the Permian Basin.

“I appreciate everybody’s confidence in being able to be seated to this on the table,” he said. “It’s been a great year. I learned a lot.”

“I learned a lot from Collin,” said TAC Chair Caitlin Smith, with Jupiter Power. “He brought a wide range of knowledge to TAC leadership, and not just the engineering side. He knows a lot about the market side and the systems and everything. I think having him here to add his perspective has been very valuable.”

Fellow Oncor employee Martha Henson has been proposed as Martin’s replacement. Smith will continue as chair.

HDL Override Change Tabled

TAC again tabled a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. Members directed their Wholesale Market Subcommittee to provide remarks on the change back to the Protocol Revision Subcommittee before they take it up again in January.

The change was approved by TAC in June. However, the board remanded it back to TAC in October over the consumer segment’s concerns that the NPRR would reward overscheduling of power that cannot be delivered. Members of that segment say that will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions. (See “2025 AS Methodology OK’d,” ERCOT Board of Directors Briefs: Oct. 9-10, 2024.)

Reliant Energy Retail Services’ Bill Barnes said he has discussed this with Eric Goff, who represents residential consumers but was unable to attend the meeting, and floated a concept from their conversation. He said it acknowledges consumer concerns about a situation where HDL overrides become a “dominant component” of the market.

“We would be more dependent on these out-of-market payments. That’s not the goal of 1190. That’s not the goal for any of us,” he said.

Barnes said an annual settlement trigger, should ERCOT find itself in a situation where it hits a threshold amount of HDL payments, would lead to a review of the protocol’s language. That would tighten the contracts eligible for some participants, he said.

Members unanimously endorsed a combo ballot that included four NPRRs and related changes to the Planning Guide (PGRR) and Nodal Operating Guide (NOGRR) and an Other Binding Document request that will do the following if approved by ERCOT’s board:

    • NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system secure area to the public ERCOT website.
    • NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ERCOT ECEII information from the market information system secure area to the public ERCOT website. The change also conforms rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; for making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and for posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website.
    • NPRR1246, NOGRR268, OBDRR052, PGRR118: insert terminology associated with energy storage resources (ESRs) into the protocols, aligning the ESRs’ provisions and requirements with those for generation resources and controllable load resources. The change applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model).
    • NPRR1254: require resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies.
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Panelists Call ITCS ‘Excellent Starting Point’

NERC’s recently submitted Interregional Transfer Capability Study (ITCS) is “a phenomenal first step,” according to participants in a webinar hosted by the American Council on Renewable Energy and Americans for a Clean Energy Grid — but there’s still much work ahead to address the U.S. grid’s mounting reliability challenges.

Speakers at the Nov. 25 webinar included former FERC Commissioner Allison Clements; Robert Taylor, vice president for transmission and new markets at Invenergy; Michael Goggin, vice president at Grid Strategies; and Cy McGeady, a fellow for energy security and climate change at the Center for Strategic and International Studies (CSIS). ACORE and ACEG hosted the forum to discuss the implications of the ITCS and potential future steps for FERC, Congress and other stakeholders.

NERC filed the ITCS with FERC Nov. 19, ahead of the December deadline for the study set by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.)

The ERO worked with the regional entities and transmitting utilities for 18 months to develop the three-part report, which FERC will post for public comment. A final installment focused on transmission between the U.S. and Canada, and between Canada’s provinces, is planned to be released in early 2025.

In the ITCS, NERC recommended 35 GW of additional transfer capability across transmission planning regions in North America to strengthen grid reliability, including two new connections between ERCOT and neighboring regions. (See NERC Releases Final ITCS Draft Installments.) The report’s authors emphasized the analysis did not account for economic issues and cost-benefit analysis, and that even with the recommended additions it would not be possible to resolve all energy deficiencies due to chronic “wide-area resource shortages.”

In ACORE’s webinar, McGeady called the ITCS an “excellent starting point” and a “baseline” for future studies. Similarly, Goggin said NERC and its collaborators “did a great job in really tight time constraints and with the pretty narrow scope that Congress gave them.”

At the same time, attendees said the narrow scope meant that NERC ended up performing a conservative analysis. Goggin said the 35 GW recommendation represents “a floor, in my view, of what you should be thinking about in terms of an optimal transmission expansion.” He noted that FERC tasked the ERO only with identifying “prudent” transmission additions to improve reliability, which meant the study understandably did not take some important factors into consideration.

“Basically, it’s just keeping the lights on. It’s not looking at the opportunity to reduce consumer costs by giving them cheaper power,” Goggin said. “More importantly, even on the resource adequacy side, it’s not looking at how transmission can help you share generating capacity. … The NERC study did look at this, but they didn’t look at how you could economically save on building power plant capacity by tapping into” neighboring regions’ generation.

McGeady added that the figures NERC used to estimate demand were based on the ERO’s 2023 Long-Term Reliability Assessment. He said the projections in this year’s LTRA likely were to be “profoundly larger, like significantly upward revisions.” This means the ITCS’ recommendations could turn out to be even more conservative than Goggin and other panelists thought.

Moderator Elise Caplan of ACORE suggested these concerns could be taken up by respondents when FERC opens comments on the study, along with how to meet the additional unmet needs that NERC identified.

Asked what actions FERC could take to improve reliability through interregional transmission ties, Clements said she believes the commission can play a significant role. She called on FERC to take the lead on interregional planning and on the cost allocation process.

“I think if you’re really, genuinely trying to get to reliability at this moment in time, across the systems that constitute this nation’s electricity systems, we need to be looking at all the tools in the toolbox,” Clements said. “When it comes to reliability, there’s often a quick jump to say you can’t retire the uneconomic thermal units that want to retire. … I think it’s imperative on the commission to say what are the quick, easy, fast ways to do that.”

“I wasn’t a champion of transmission just because I think transmission is great. In fact, it would be a lot easier if we didn’t have to build it,” Clements added. “I’m a champion of transmission because it is a way to get to cost-effective reliability for customers.”