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December 24, 2024

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NJ Awards Contracts for 3.7 GW of OSW Projects

The New Jersey Board of Public Utilities awarded contracts to a new set of offshore wind proposals Jan. 24 (Docket No. Q022080481). 

The Leading Light Wind and Attentive Energy Two projects would total 3,742 MW of capacity. The contract awards are a shot in the arm for the Garden State’s highest-in-the-nation offshore wind goals after Ørsted canceled the Ocean Wind projects in late 2023. 

However, the bounceback will not be immediate. 

The new projects are not expected to come online until 2031 and 2032. Ocean Wind 1 had already begun onshore construction, planned to start offshore construction this year and had projected completion in 2025. 

Also, Ocean Wind 1 was a mature project, with a stack of approvals in hand including the all-important green light from the U.S. Bureau of Ocean Energy Management. 

Attentive Energy Two (1,342 MW) and Leading Light (two phases of 1,200 MW each) must now navigate extensive local, state and federal review processes before beginning construction.  

They must also avoid the financial and supply chain pressures that doomed the Ocean Wind projects — but many analysts expect those constraints to ease significantly for the U.S. offshore wind industry in the next few years. 

In fact, the Attentive and Leading Light projects themselves will help ease the supply chain crunch, as both development teams have committed to expand New Jersey’s new offshore wind manufacturing and operations facilities, including fabrication of towers and monopile foundations. 

In one example, EEW is expected to produce more and larger monopiles in-state because of this commitment. 

New Jersey officials said Jan. 24 that the projects will result in a guaranteed direct impact of 5,218 job-years and $2.5 billion in spending. Adding indirect and induced jobs and spending, the impact rises to an estimated 27,103 job-years and $6.8 billion. 

Ambitious Goals

New Jersey Gov. Phil Murphy (D) set a goal of 3,500 MW of offshore wind in 2018, then bumped it up to 7,500 MW in 2019 and 11,000 MW in 2022. 

The state’s first solicitation yielded Ocean Wind 1 (1,100 MW). The second yielded Atlantic Shores Offshore Wind (1,510 MW) and Ocean Wind 2 (1,148 MW). 

The third solicitation drew interest from four developers: Atlantic Shores, Attentive, Community Offshore Wind and Leading Light; Community subsequently withdrew its bid. 

An expedited fourth solicitation is underway, with contract awards expected to be announced in the first half of this year. 

Cancellation of Ocean Wind 1 and 2 was announced on Halloween 2023 — a nasty trick for those who had expended political capital on behalf of the projects and a delightful treat for the many opponents of offshore wind in New Jersey. 

Opposition to offshore wind has been particularly vocal along the Jersey Shore, due to cost, environmental impact and visibility from popular beaches. On this last point, Leading Light and Attentive would be more than 40 and 47 miles from land respectively at their nearest point, and all but impossible to see from shore. 

Those opposed to offshore wind due to its cost will have the following numbers to work with: 

Leading Light Wind offered a first-year price of $112.50/MWh for offshore renewable energy credits (OREC). That works out to a 20-year levelized OREC price of $139.53 and a 20-year levelized net cost of $70.05 once revenue credits and avoided costs are factored in. Average monthly cost to ratepayers (in 2023 dollars) is estimated at $3.71 residential, $31.86 commercial and $278.42 for industrial. 

Attentive offered a first-year price OREC price of $131, a 20-year levelized OREC price of $165.14 and a levelized net cost of $96.75. Average monthly cost to ratepayers is estimated at $3.13 for residential, $26.87 for commercial and $234.80 for industrial. 

For comparison, the Ocean Wind 1 contract award (Docket No. Q018121289) in 2019 specified a first-year OREC price of $98.10, a levelized 20-year price of $116.82 and a levelized net cost of $46.46. Estimated monthly ratepayer impacts (in 2019 dollars) were $1.46 residential, $13.05 commercial and $110.10 industrial.  

A reporter asked BPU senior scientist Kira Lawrence on Jan. 24 why Attentive Energy Two’s ORECs would be noticeably more expensive than Leading Light’s. 

“There is an economy of scale associated with the Leading Light Project,” she replied. “It’s a 2,400-MW project, so there are a number of economies of scale that can be achieved with a larger project size. Attentive is a 1,342-MW project.” 

The reporter did not ask about the contract that Attentive is now negotiating with New York for the proposed Attentive Energy One in another portion of the same lease area off the New Jersey coast. Its capacity would be 1,400 MW, presumably creating some economies of scale. 

Kate Klinger, a senior member of Murphy’s staff, added that bids were evaluated for not just cost but their holistic benefit to the community. “Some of what is included in that pricing is direct support for offshore wind supply chain facilities, for workforce development, benefits that will be felt directly in communities in New Jersey as well.” 

Leading Light is a joint venture of Invenergy and energyRE. It said Jan. 24 it was reviewing the BPU order and looking forward to working with New Jersey to advance its clean energy transition. 

Attentive Energy Two is a joint venture of TotalEnergies and Corio. 

Mixed Reaction

The abrupt cancellation of Ocean Wind 1 and 2 — even after a financial concession by the state and even amid preparatory work by the developer — was a bitter setback for state leaders and offshore wind proponents. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

New Jersey wind

New Jersey Board of Public Utilities President Christine Guhl-Sadovy | NJ BPU

BPU President Christine Guhl-Sadovy alluded to Jan. 24 before the board’s unanimous vote in favor of the two contracts. 

“In spite of some setbacks,” she said, “we’re on track. If anything, this solicitation award shows that we’re moving full steam ahead. These two projects will help cement New Jersey’s position as an offshore wind leader and bring the clean energy and economic benefits to our state that have been such a critical part of Gov. Murphy’s agenda.” 

Commissioner Zenon Christodoulou went a step further, warning the developers that the BPU would not let the state get skunked again, promising “fanatical, even tyrannical oversight” of progress, if necessary. 

“The contracts we are awarding are tight and hold the awardees accountable to our production schedules and pricing schemes,” he said. “We will enforce those guarantees with relentless oversight and unwavering defense of our ratepayers. There will be no hat-in-hand requests, no unforeseen expenses, no nickel-and-diming.” 

Clean energy groups greeted Jan 24’s’s action warmly. 

New Jersey wind

New Jersey Board of Public Utilities Commissioner Zenon Christodoulou | NJ BPU

Oceantic Network CEO Liz Burdock said: “New Jersey reasserts its leadership in the U.S. offshore wind sector with today’s 3.7-GW commitment and securing new supply chain investments in towers, foundations, and secondary steel manufacturing. The U.S. offshore wind market is entering a new phase of development; today’s action capitalizes the state’s early investments in a coordinated transmission system, the New Jersey Wind Port, and the EEW monopile facility to accelerate development and position the state at the center of the nation’s supply chain.” 

Anne Reynolds, vice president for offshore wind at American Clean Power, said: “Today is a key step towards achieving the state’s goal of a 100% clean energy economy by 2035. Offshore wind will bring huge economic benefits to the state and region, creating jobs and new investment opportunities for manufacturing companies and suppliers to support the necessary infrastructure needed for this new and growing industry. It is also a significant commitment to developing the New Jersey Wind Port which will generate up to $500 million in new economic activity annually for the Garden State.” 

Advanced Energy United Managing Director Nathan Willcox said: “Today’s awards set the stage for a vibrant offshore wind future in New Jersey. Offshore wind is critical to growing New Jersey’s economy, hitting our clean energy goals and improving grid reliability, and we are eager to see these projects move forward.” 

Support was far from universal, however. 

SaveLBI, a Jersey Shore activist group that sued the federal government in an attempt to block Ocean Wind, picked apart the BPU decision in a series of social media posts. 

“A bad day indeed,” it said. 

U.S. Rep. Jeff Van Drew (R-N.J.) said on X: “Today, NJBPU unanimously approved two new offshore wind projects despite overwhelming disapproval from New Jerseyans. The Murphy admin has once again ignored the will of the people in order to line the pockets of offshore wind companies at the cost of NJ ratepayers.” 

On the Facebook page of Protect Our Coast, commentary on the news ranged from snark to dismay to anger, and suggested strongly that placing the turbines out of sight beyond the horizon would not mollify most opponents. “WTF. THEY WANT WAR,” one said. 

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Texas PUC Sends ESR Change back to ERCOT

Texas regulators have remanded back to ERCOT a controversial protocol change attempting to regulate energy storage resources, but not before stripping out language related to state of charge (SOC) and enforcement processes.

The unanimous decision during the Public Utility Commission’s Jan. 18 open meeting is a victory, albeit temporary, for the energy storage sector, which has been battling the proposed change since last summer. As written, nodal protocol revision request (NPRR1186) sets a one-hour SOC for energy storage resources participating in two ancillary services (ERCOT contingency reserve service and non-spinning reserve). It also includes penalties of up to $25,000 per violation. (See “PUC Delays Approval of Rule Change that Penalizes Storage Resources,” Texas Public Utility Commission Briefs: Nov. 30, 2023.)

Storage developers say the new rules hold energy storage resources (ESRs) to higher standards than conventional thermal resources and could result in fines if batteries fall below SOC thresholds and still deliver the power promised.

ERCOT staff filed a report before the meeting trying to address questions raised by the PUC in November. It said with ESR capacity projected to grow from 4.4 GW to more than 20 GW by 2026, the rules are necessary to preserve reliability. The data presented showed similar failure rates for ESRs and for thermal resources involved in the ancillary service markets (54445).

Commissioner Jimmy Glotfelty, who has declared the rule change to be “discriminatory” to energy storage, was not swayed.

“They all fail. Singling out ancillary services providers of battery storage is discriminatory. Gas plants fail. Nuclear plants fail. Coal plants fail,” he said. “That’s why we over-procure ancillary services. I just cannot pass something that puts a compliance penalty on a type of service when the data from ERCOT shows that dispatchable resources fail in the same types of services.”

“It really is a big deal from a liability perspective to make sure that those ancillary services can provide the products that we need for the duration that we need them to,” Dan Woodfin, ERCOT’s vice president of system operations, told the PUC.

Commissioner Lori Cobos said ERCOT should withdraw or table NPRR1209, a directive from the Board of Directors as NPRR1186 ran into trouble. ERCOT staff said Jan. 24 the rule change was tabled in November within the stakeholder process to allow the commission to work out its issues with 1186, which also was a board priority item.

Both measures are seen as stopgaps until ERCOT deploys real-time co-optimization, currently targeted for the latter half of 2026.

The ERCOT board now will take up 1186 and the PUC’s changes for approval before they get sent back to the commission for a final review and vote.

The open meeting took place the day before Thomas Gleeson was appointed as the PUC’s chair. Gleeson was formally sworn in Jan. 23. (See Abbott Names PUC Executive Director as Chair.)

VoLL Study to Begin

The Brattle Group will open a value-of-lost load (VoLL) survey of ERCOT retail customers in March. The results will be reported back to the PUC in August as part of the grid operator’s effort to quantify VoLL (55837).

ERCOT is analyzing the frequency of load shed, but also its magnitude and duration, with an expected unserved energy metric. According to a staff filing, every 1% improvement in a plant’s weatherization reduces the needed for 175 MW of capacity.

The commission also requested comment on DC ties, such as the Southern Spirit line. Glotfelty asked PUC and ERCOT staffs to model the effect of that line had it existed Sept. 6, the last time ERCOT was in emergency operations (55984). (See ERCOT Voltage Drop Leads to EEA Level 2.)

The PUC will discuss the issue in February.

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DOE, BOEM Kick off West Coast Offshore Wind Tx Planning

The U.S. Department of Energy and Bureau of Ocean Energy Management on Jan. 17 kicked off a series of stakeholder workshops to address the specific challenges to siting transmission for the first generation of West Coast offshore wind projects.

Agency representatives said the meetings aren’t intended to produce siting or regulatory decisions, but to establish a set of recommendations and actions for publication as an addendum to the Atlantic Offshore Wind Transmission Action Plan, released in 2023. (See Feds Release Road Map for Offshore Transmission Grid.)

The Biden administration set a goal of deploying 30 GW of offshore wind in U.S. waters by 2030 and an additional 15 GW of floating offshore wind — the type needed in the deeper waters off the Pacific Coast — by 2035.

Speaking during the Jan. 17 virtual meeting, Jocelyn Brown-Saracino, offshore wind energy lead at DOE, highlighted that the U.S. now has a combined potential capacity of approximately 52 GW of offshore wind, up nearly 50% from three years ago. And in the last year, she noted, the global floating offshore wind pipeline grew from around 60 GW to about 103 GW.

Planners are looking to the West to accelerate that progress: California has established a goal of deploying 25 GW of offshore wind by 2045, and Oregon set a target of 3 GW by 2030.

But the West Coast currently lacks the transmission infrastructure to meet those goals. And while the Atlantic Offshore Wind action plan serves as a road map for planning in the Pacific, development along the West’s more remote coastlines comes with its own unique obstacles.

“We know that bringing this energy to shore poses a host of challenges,” said BOEM Director Liz Klein. “On the West Coast, the lack of off- and onshore transmission pathways to access offshore wind development and the harsh ocean energy environment [are challenges]. We need to work together to understand these challenges and to identify potential solutions.”

Another challenge lies in the complications of developing transmission that extends beyond a federal lease area. BOEM’s authority over transmission siting starts at the outer continental shelf, allowing the agency to grant easements and rights-of-way for the production, transmission and transportation of energy sources. But BOEM does not have jurisdiction over landfall sites, so a project developer must work with regional and state entities and utilities to determine the appropriate points of interconnection.

In convening the workshops, the agencies hope that engaging states, transmission operators, tribal nations, ocean users and others will foster collaboration for the development of offshore wind. The series is part of a broader effort, and DOE is finalizing the scoping phase and beginning technical analysis.

Scoping in early 2023 identified gaps in planning, including the need for more interregional coordination and collaboration with tribal governments. DOE is working with the National Renewable Energy Laboratory (NREL) to engage tribes through the Tribal Nation Offshore Wind Transmission Technical Assistance Program, which will offer educational resources, training, technical assistance and funding for participation.

Technical Progress

The effort will also get significant technical support from U.S. national laboratories. Last May, the Pacific Northwest National Laboratory (PNNL) and NREL launched the West Coast Offshore Wind Transmission Study, which over the span of 20 months will explore transmission options to support offshore wind development through 2050. The labs reviewed 13 technical studies on offshore wind development, identified key themes in the region and determined that coastal interconnection points lack existing capacity for integrating offshore wind.

Mark Severy, a PNNL adviser to DOE, also identified gaps in the body of work reviewed, finding that most studies were focused on a single region or state and lacked consensus on the optimal technology or topology for offshore grid infrastructure.

According to Travis Douville, wind systems integration portfolio manager at PNNL, the study is the first of its kind to assess the entire West Coast. It considers a variety of guiding questions, including how much offshore wind should be developed through 2050 and where, and lays out nine tasks designed to help answer those questions.

To determine where transmission is needed, task two identified a series of zonal capacity expansion targets that span the Western Interconnection and provide information on how much offshore wind could be brought online. The targets will then be used to build nodal representations to simulate information on the economic dispatch of individual generators and model various sensitivities such as weather.

Tasks three and four involve the consideration of various siting conflicts, such as ocean co-use and topology. Douville said Pacific coastline is particularly challenging due to the depth of the water and the contour of the sea floor and canyons.

The team is constructing four topology sets to help consider where projects should be built. With those in place, the researchers will conduct weather-synchronized simulations of historical and future load, wind and solar patterns to provide insights into the types and location of needed generation.

After the modeling is complete, the labs will quantify the changes to capital and production cost, emissions, resource adequacy and resilience characteristics to the system, as well as the socioeconomic impacts and benefits to coastal and ocean co-use communities.

Lessons Learned

Alissa Baker, senior technical adviser for offshore transmission with DOE’s Grid Deployment Office, discussed lessons learned from developing the Atlantic action plan.

“We’re not inventing the wheel from scratch here,” Baker said. “We’re starting with a plan and hopefully refining and learning from the things that went well and the things that could go even better here.”

Key among the insights, Baker emphasized the importance of partnerships, particularly among state and regional entities and with tribes. She also highlighted the need for greater interregional offshore topology planning that spans ISO, RTO and state boundaries.

Baker’s presentation noted that FERC Order 1000 “sets forth the current generic federal requirements for considering potential interregional transmission” but requires only “coordination” between regions. “Fully integrated interregional planning is allowed but not required and, to date, has not been successfully implemented for any large-scale infrastructure,” it said.

Baker also suggested updating NERC standards for offshore wind generation to ensure they’re applicable to ocean transmission infrastructure and offshore wind generation tie-lines.

Another key recommendation was the support of local communities through community benefit agreements between project developers and those impacted.

“We want to make sure that the communities that are impacted by infrastructure are benefiting from that infrastructure and that the benefit is something that is greater than the impact they’re perceiving,” she said.

The Jan. 17 meeting closed with a lighthearted prerecorded discussion between DOE Deputy Secretary David Turk and Laura Daniel-Davis, acting deputy secretary at the Department of the Interior, which oversees BOEM.

“The Biden-Harris administration has an ambitious goal of deploying 30 GW of offshore wind by 2030,” Daniel-Davis said. “When we get there, that’s enough to power 10 million homes and we’re going to cut 78 million metric tons of carbon pollution … all while we build a domestic supply chain, creating these good-paying union jobs, and we’re lowering consumers’ energy prices.”

Turk reflected on the Atlantic convening series workshops and their benefit to transmission planning in the West.

“It was an incredibly good forum, and I think the West Coast can do an even better job of these kinds of discussions going forward,” he said.

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Repeal Effort Begins on Michigan Renewable Siting Laws

LANSING, Mich. — Opponents of Michigan’s new laws governing siting for renewable wind and solar energy projects have until May 29 to present petition signatures from at least 356,958 registered voters to potentially put a repeal on the ballot. 

The group backing the effort already is trying to collect signatures. Technically, as an initiated act, under Michigan’s constitution, the Legislature could enact the changes the proposal would make once enough signatures are gathered (and the constitution would forbid Gov. Gretchen Whitmer (D) from vetoing it). But no observer expects the Democratically controlled legislature to enact the proposal. 

If the legislature does not approve the proposal, it would go to the voters at the next general election. Citizens for Local Choice is spearheading the petition effort. 

Despite several attempts, officials with the Lenawee County-based group could not be reached for comment.  Lenawee County is a mostly rural county on Michigan’s southern-most tier bordering Ohio. 

Lenawee County Commissioner Kevon Martis has been quoted in newspaper articles saying the organization isn’t opposed to alternative energy, but the provisions in PA 233, 2023 give siting authority for solar and wind projects to the state’s Public Service Commission instead of local authorities. 

The centralized siting provision was a main reason Republicans refused to support the bills in the legislative process. 

Martis told the Michigan Board of State Canvassers the repeal effort, “has been about restoring local voices when it comes to wind and solar options being placed in their communities,” 

Norm Stephens, a committee member for Citizens for Local Choice, told the Adrian Daily Telegram, the Lenawee County newspaper, “we refuse to sit on the sidelines as local control gets stripped from our communities.” 

The new law is an important component of Michigan’s efforts to achieve net zero carbon emissions by 2040. It was enacted following a series of situations in which local governments, primarily in rural counties, enacted new zoning provisions blocking solar or wind projects. In some cases, residents objected to alternative energy projects over concerns about noise, attractiveness and the potential loss of farmland. 

Supporters of the law argue it helps protect the property rights of farmers and others to sell and use their property for different purposes. 

Nick Dodge, communications director for the Michigan League for Conservation Voters, said of the petition drive: “This reckless proposal hurts farmers looking to keep multigeneration land in their families and strips them of their property rights, all while harming workers that can benefit from clean energy tax revenue and jobs. Repealing this important law will only lead to an increase in utility rates for Michigan families and small businesses.” 

The state canvassers reviewed the proposed language for the petition and the form of the petition before giving its approval to gather signatures. That step is not required in Michigan law but generally is sought by groups leading petition drives to minimize the chance the petition could be thrown out on legal technicalities. 

Lawyers for supporters and opponents of the proposal worked on a compromise on the 100 words that would outline the proposed initiated act. It reads: 

“Initiation of legislation to: amend the clean and renewable energy and energy waste reduction act by eliminating the requirement that applicants undergo state certification before construction of certain wind and solar energy facilities and energy storage facilities. Under current law, in addition to local approval, applicants for construction of these facilities must obtain state certification, which requires meeting state requirements, including: an application fee; public comment; assessment of environmental, natural resources and farmland impact; wages and benefits requirements for workers; setback distance; size and height of structures; and amount of light and sound emitted.” 

The group needs to collect nearly 357,000 signatures, equivalent to 8% of the total votes for governor in the 2022 election, as required by the constitution. The group said on its website it plans to collect 550,000 signatures to ensure the proposal gets the minimum number. The organization is looking to raise between $7 million and $10 million for an anticipated campaign to win voter approval. 

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Crypto Load on MISO-SPP M2M Constraint Draws Complaint from Montana-Dakota Utilities

Montana-Dakota Utilities Co. has filed a complaint against MISO and SPP over a market-to-market flowgate chronically congested by a new cryptocurrency mining operation in SPP.

The utility said the RTOs are violating their joint operating agreement by conducting “unwarranted” and “unjust” M2M congestion coordination on the Western Area Power Administration 230-kV Charlie Creek-Watford line in North Dakota (EL 24-61).

Montana-Dakota Utilities — a MISO member — said its customers have been overcharged about $18 million for congestion on Charlie Creek-Watford. It said FERC should order a stop to MISO and SPP’s M2M coordination on the line, direct SPP to refund payments MISO made to it for M2M coordination and order refunds for “duplicative payments made by Montana-Dakota for M2M coordination.”

The company also said FERC should pronounce MISO and SPP’s interregional coordination process unreasonable because it allows MISO or SPP to “insist on continued coordination of a flowgate” even when the coordination is not shown to reduce congestion. MISO and SPP should be conducting M2M coordination only when it’s effective at cutting congestion, Montana-Dakota argued.

Montana-Dakota maintained the RTOs’ interregional coordination process never should have been enacted in the case of Charlie Creek-Watford because the constraint “was of local, not regional, concern.”

“SPP’s decision to enact and maintain M2M coordination for the local issue of congestion on the Charlie Creek-to-Watford City line violated and continues to violate [the JOA] and constitutes an unjust and unreasonable practice,” the utility told FERC. If SPP “continues to insist on use of M2M coordination for the Charlie Creek-to-Watford City line congestion issues, then Montana-Dakota and its customers will continue to be unfairly and unjustly assessed overlapping congestion charges.”

MISO’s Independent Market Monitor late last year called attention to the flowgate as a major source of congestion since the line began delivering power to 220 MW in new load from a cryptocurrency mining operation. (See MISO and IMM: M2M Flowgate Issue with SPP not Sustainable, May Require Litigation.)

MISO IMM David Patton said MISO and SPP should revoke Charlie Creek-Watford’s status as an M2M constraint because MISO can offer little congestion relief for the line and it’s costing MISO millions in payments.

MISO staff said new load was allowed to be activated in an already-constrained SPP load pocket with planned transmission upgrades for the area not in service yet.

MISO itself hasn’t ruled out litigation with SPP over the overworked flowgate.

In mid-January, MISO deputy general counsel Kristina Tridico confirmed that MISO pursued alternative dispute resolution with SPP over the constraint and is at the “beginning stages” of negotiations.

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NEPOOL Nears a Vote on Order 2023 Compliance

ISO-NE reviewed changes to its Order 2023 compliance redlines with stakeholders at the NEPOOL Transmission Committee (TC) on Jan. 23 as the committee prepares for a vote on compliance in February. Multiple clean energy organizations, meanwhile, proposed compliance amendments. 

Al McBride, director of transmission services and resource qualification at ISO-NE, first summarized the tariff redlines at the December meeting of the TC. (See ISO-NE Details Order 2023 Tariff Changes.) At the January meeting, McBride detailed redline changes largely intended to clarify and clean up aspects of ISO-NE’s compliance proposal.  

McBride also provided an update on the status of the interconnection queue, which consists of 203 active projects totaling 39,563 MW. Of those projects, 68 accounting for 11,423 MW have completed their system impact studies, which means they will not need to enter initial transitional cluster study.  

System impact studies for 5,573 MW worth of late-stage interconnection requests are expected to be completed before the current cutoff point for these projects to avoid needing to enter the transitional cluster.  

Representatives from Advanced Energy United, RENEW Northeast, New Leaf Energy, Cypress Creek Renewables and Glenvale Solar provided updates on their compliance amendments and outlined the proposals they will offer for a TC vote in February. 

New Leaf’s first proposal, supported by Advanced Energy United, would have the RTO extend the cutoff date for system impact studies that are expected to be completed prior to the start of the transitional cluster study but are not completed by the currently proposed cutoff point.  

McBride told the TC that nine projects amounting to 1,485 MW are on track to complete their system impact studies after the current cutoff point but prior to the first cluster study.  

New Leaf also proposed to calculate withdrawal penalties for the transitional cluster study strictly based on study costs incurred within this cluster, excluding any study costs from before the cluster from the penalties, to “fairly calculate withdrawal penalties for all projects in the transitional cluster.” 

The company’s third proposal would require ISO-NE to determine during the customer engagement window whether interconnection customers will be included in a cluster subgroup. The RTO said it “does not intend to use subgroups in the clustering process,” but would have the option to create subgroups. 

Cypress Creek, a solar and storage company, said three of its four previously proposed amendments have been adequately addressed by ISO-NE, and has withdrawn the fourth amendment related to site control because the issue is subject to an ongoing rehearing request with FERC.  

Advanced Energy United, which previously expressed concern about the extended length of the cluster timeline compared to the process proposed by FERC, is proposing to create an “Interconnection Reforms Working Group” aimed at reducing cluster study timelines. 

“At the heart of Order 2023 was a resolve to accelerate interconnection study and processing timeframes, and we must strive to meet the order’s requirements even if we cannot commit right now,” said Alex Lawton of United.  

The clean energy industry association also proposed to increase guidance and transparency around the selection of alternative transmission technologies as upgrade solutions, including the explicit consideration of dynamic line ratings.  

United and RENEW jointly proposed to provide an opportunity for interconnection customers to reduce project size if ISO-NE determines a restudy is needed. This opportunity would extend only to modifications that do not affect the cost or timing of another project. 

“Order 2023 provides a clear and firm basis for allowing reductions that are not material,” United said. 

RENEW also proposed that ISO-NE separately calculate costs for Capacity Network Resource (CNR) Interconnection Service and Network Resource (NR) Interconnection Service. The clean energy nonprofit also proposed to “allow CNR Interconnection Requests to downgrade their requested service to NRIS” in response to the results of a cluster study, restudy, or facilities study, with some limitations.  

The organization also proposed changes to let new resources with completed SIS and a commercial operation date prior to June 1, 2028, to participate in reconfiguration auctions in 2024. 

Glenvale Solar proposed a series of amendments that would incentivize cash deposits over letters of credit for commercial readiness deposits (CRDs), reduce the first posting of CRDs and reduce CRDs for modifications of existing generation that do not add capacity. 

The TC will vote on the ISO-NE compliance proposal and stakeholder amendments on Feb. 15. 

Longer-term Transmission Planning

Brent Oberlin of ISO-NE provided additional information on the RTO’s efforts to create a new process for transmission projects that address needs identified in its longer-term transmission studies. (See ISO-NE Details Order 2023 Tariff Changes.) 

The new process is being developed in coordination with the New England States Committee on Electricity (NESCOE), which represents the interests of all six New England states. The process is intended to establish “the rules that enable the states to achieve their policies through the development of transmission to address anticipated system concerns and the associated cost allocation method,” Oberlin said.  

For project bids to be eligible for selection, a quantitative comparison of benefits and costs must show net benefits. Oberlin told the TC that this analysis will include production cost and congestion savings, avoided transmission and local resources needed to meet demand, and reductions in losses. 

The factors considered do not explicitly include climate or public health benefits, which several stakeholders expressed an interest in including as considerations.  

NEPOOL also proposed the creation of a supplemental process that would enable it to select projects that do not meet the cost-benefit threshold.  

“This supplemental process would allow one or more states to fund costs if the [benefit-cost ratio, BCR] threshold was not met in order to move the project forward,” said Sheila Keane of NESCOE, who noted this process would be used only if no project proposals meet the threshold. 

“Costs commensurate with the BCR tariff criteria will be regionalized with one or more states agreeing to cover the remaining costs,” Keane added. “If the NESCOE selected project has BCR = .95, the region pays for 95% of project costs on a load-share basis and one or more states fund the remaining 5% of costs.” 

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Former Opponents Shift Position on CAISO ‘Regionalization’

Some of the staunchest in-state opponents of California’s past efforts to “regionalize” CAISO have shifted their views on the issue. 

The change of heart comes as participants in the West-Wide Governance Pathways Initiative work to build the framework for an independent Western RTO expressly designed to include — and use the capabilities of — the ISO.  

Previous attempts to expand CAISO into a broader regional organized electricity market have been met with strong opposition both inside and outside California.  

For electricity sector stakeholders in the rest of the West, the ISO’s lack of independent governance — its board is appointed by the governor of California — has long been a non-starter for deeper integration.  

To address the governance problem, California supporters of CAISO regionalization attempted three times to advance state legislation for an independent ISO board. Three times they failed in the face of in-state opposition. 

In 2016, then-Gov. Jerry Brown (D), a key supporter of an expanded and independently governed CAISO, halted the first such effort before a final bill could be crafted, citing the need to give state agencies more time to put together a politically acceptable proposal. (See Governor Delays CAISO Regionalization Effort.) But that pause yielded little progress, and AB 813, a bill to convert CAISO into a multistate entity, died in committee at the end of both the 2017 and 2018 legislative sessions in the face of opposition from a handful of key constituencies.  

The reasons for resisting that bill varied.  

For the International Brotherhood of Electrical Workers (IBEW) labor union, the change would expand the boundaries of the CAISO balancing authority area in a way that could mean that the portion of projects that California’s renewable portfolio standard required to be interconnected directly to the ISO’s BAA could be built outside the state, reducing job opportunities for members.   

The California chapter of the Sierra Club worried that an RTO binding CAISO with PacifiCorp, a six-state utility with a large coal generation portfolio, would water down the impact of California’s environmental policies pushing for renewable generation. 

Groups such as the California Municipal Utilities Association (CMUA) and consumer advocacy group The Utility Reform Network (TURN) warned about the potential effect on consumer rates and the ISO’s mission to serve the interests of Californians. 

But sentiments among previous opponents appear to be shifting as the Pathways Initiative, launched last summer by a group of utility commissioners from five states, works to build an independently governed RTO on the foundation of CAISO’s real-time Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). RTO Insider reached out to representatives of those groups to learn more about how and why their views have changed. 

‘Fair and Balanced’

Marc Joseph, an IBEW representative who sits on the Pathways Initiative’s Launch Committee, spoke about labor’s opposition to AB 813 during a Dec. 15 update from the committee.  

“We opposed the prior legislation because it would have resulted in exporting thousands of jobs building new generation and transmission created by California’s RPS [Renewables Portfolio Standard] law from California to other states,” Joseph said. 

But the initiative’s approach to the governance issue has led the union to reconsider its position.  

“The key substantive difference between the prior legislation and the current options is under all the current options the CAISO’s balancing authority function would remain intact,” Joseph said. “We’re supporting the Pathways Initiative because, like everyone else here, we’re acting in our own rational self-interest.”  

In an interview with RTO Insider, Joseph again emphasized that regionalizing without expanding the physical boundaries of CAISO’s BA would keep jobs in California and benefit ratepayers.  

“We do see potential benefits in optimizing dispatch of plants over a wider footprint, and that will produce cost savings to consumers and therefore free up money to do the other things we need to do, such as building out the distribution grid,” he said. “The question now is, how do we get more entities to participate in EDAM? That’s why the Pathways Initiative exists.”  

Like IBEW, CMUA also opposed prior legislation, largely due to iterations of the bill that it said could have had adverse impacts on consumers. But CMUA Executive Director Barry Moline said the agency was never against regionalization.  

“Our concern with it was the way governance was established (who gets to serve on and advise the board),” Moline told RTO Insider in an email. “There was very little direction, and we worked hard to — and this is important — make sure consumers were not harmed in the process. By harm, we mean that we are concerned about affordability, and without any controls or accountability on governance, our imperative to address affordability would not be of concern.” 

Like other industry stakeholders, CMUA was also concerned over what it thought was a rushed timeline to transform CAISO into an RTO. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)  

But the Pathways Initiative takes an incremental approach, providing participants the opportunity to ease into an integrated market that could turn into an RTO with time.  

“With the experience and trust built through the WEIM, we are working through the Pathways Initiative to build the EDAM governance model and the process to make it work,” Moline said. “We believe that done correctly, with significant and continuous stakeholder input, we will continue to build trust and provide consumer and environmental benefits. It is this stepwise process that is creating trust among participants, and we are eager to continue to develop it with maximum stakeholder engagement.” 

Environmental concerns also played role in the failure of AB 813, despite getting support from prominent conservation groups such as the Natural Resources Defense Council, Environmental Defense Fund and Western Resource Advocates, who all viewed regionalization as a way to share renewable resources across a wider geography in order to reduce electricity-based emissions across the West.  

But California’s chapter of the Sierra Club had voiced concern that an expanded CAISO would reduce the effectiveness of the state rules to eliminate the import of coal-fired generation, especially given that PacifiCorp was one of first utilities to signal its intent to join an expanded ISO. Additionally, the group was concerned that AB 813 eliminated emissions tracking as a core principle, which could lead to carbon leakage. 

But the WEIM now has a rigorous GHG accounting in place, a program that will be extended to the EDAM. And since its launch in 2014, the WEIM has also been responsible for avoiding more than 904,000 metric tons of GHG emissions through reduced curtailment of renewables, according to CAISO estimates. 

That record of reductions may account for why the Sierra Club appeared to move its attention away from the most recent efforts to regionalize CAISO just as the process begins to heat up again. When reached for comment, the group said it was unable to find a staff member who could speak to the issue.   

TURN did not respond to a request for comment for this story, but Moline addressed past environmental and ratepayer concerns, saying “WEIM is providing great value to consumers and the environment.” 

He also voiced optimism about the Pathways Initiative. 

“It’s highly engaging and requires a lot of time from everyone impacted by a coordinated Western energy market. We see it as a smart, can-do group of stakeholders who are working hard on a fair and balanced path forward,” he said. 

Robert Mullin contributed to this article. 

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NERC Recommends Phased Approach to INSM

Internal network security monitoring (INSM) is a worthy tool for maintaining security on the power grid but will require a “solid foundation” to ensure it is effectively implemented in low- and medium-impact cyber systems, NERC said in a study submitted to FERC on Jan. 18 (RM22-3). 

FERC ordered NERC to study INSM last year in its order mandating that the ERO develop standards requiring INSM at high-impact cyber systems and medium-impact systems with external routable connectivity (ERC). (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) The commission said NERC should examine the feasibility of implementing INSM in low-impact cyber systems and medium-impact systems without ERC. 

As defined in FERC’s order, INSM is designed to detect “intrusions and malicious activity within a trusted network zone.” In the report, NERC elaborated that INSM works “under the assumption that attackers have already compromised the network perimeter, or that the attacker is an insider with trusted network access.” The ERO compared INSM to security cameras within a secure building, monitored by personnel who “are alert to anything that looks suspicious.” 

NERC’s study was based on information submitted by registered entities as part of a data request issued by the ERO last year. (See NERC Issues Cybersecurity Data Request.) Questions in the data request included the number of facilities with low- and medium-impact cyber systems, with and without ERC; network configurations for several types of medium-impact systems; and entities’ assessments of the challenges involved in extending INSM to more systems. 

NERC submitted both public and nonpublic versions of the report to the commission. The main difference is that information that the ERO considers Critical Energy/Electric Infrastructure Information is redacted from the public version on the grounds that it “could be useful to a person planning an attack on critical electric infrastructure.” 

In practice this means that most of the specific information based on registered entities’ responses — such as the location and type of low- and medium-impact systems, challenges with implementing INSM and attack surface area — is not available in the public version. 

However, NERC’s recommendations were still visible. The ERO determined that while INSM can help “detect and respond to the machine speed, scale and scope of cyberattacks,” extending the scope of NERC’s proposed INSM standards will require considerable time and effort. 

One reason for this is the “sheer number” of facilities with low-impact cyber systems, NERC said, along with the “wide variety of legacy systems,” particularly at low-impact facilities, that may not be compatible with modern INSM tools and technologies. Entities also expressed “pessimistic expectations” regarding the likely compliance requirements for standards requiring the implementation of INSM. 

Concerns were also raised about finding staff to add INSM measures to existing systems, with the industry already experiencing a shortage of personnel qualified to “perform [the] highly technical work.” 

In the report’s conclusion, NERC acknowledged the challenges of adding INSM to low- and medium-impact cyber systems but asserted that the measures are too important to ignore. The ERO recommended that its Reliability and Security Technical Committee lead industry in developing a “roadmap” for the improvement of cybersecurity controls, including a phased approach for updating the Critical Infrastructure Protection (CIP) standards to require INSM. 

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Renewable Thermal Group Releases Industrial Decarbonization Plan

The Renewable Thermal Collaborative (RTC) on Jan. 23 released an Electrification Action Plan that contends electrification should be a major component of any plan to decarbonize industrial thermal energy use.

“When cost-competitive heat pumps, electric boilers and electrified thermal batteries are powered by low- or zero-carbon electricity, they can significantly and immediately reduce emissions,” the report said. “Deployment of improving electrification technologies like high temperature heat pumps can reduce emissions even more over the long term.”

Only 5% of the industrial heat in the U.S. is electrified, so near-term opportunities abound.

Industrial heat pumps (IHPs) can replace fossil fuel-powered systems for applications under 130 degrees Celsius, which represents 29% of industrial thermal demand. Electric resistance technologies can electrify processes up to 1,800 degrees Celsius.

“More than 75% of the emissions from industrial heating come from low- and medium-temperature (<500°C) industrial applications, which are [predominantly] served by natural gas,” the paper said. “These applications include washing, drying, sterilizing, distilling and more and are common in the food, paper and chemicals sectors. Industrial heat pumps, electric boilers and thermal battery systems can replace fossil fuel-powered technologies in these industrial processes to significantly reduce emissions by 2030.”

Thermal energy storage (TES) systems, or thermal batteries, can deliver heat and steam up to 750 degrees Celsius now and should be able to support temperatures of 1,500-1,800 degrees by the next decade.

While the technologies are available now, they are more expensive than producing steam and heat from natural gas due to upfront costs, related infrastructure upgrades and the higher cost of electricity compared to gas.

“Industrial energy buyers seeking to deploy electrification technologies must pay for a variety of expenses throughout project development and operation, including new equipment, process integration, electricity infrastructure upgrades and electricity,” the paper said. “Despite findings that electrification technologies like IHPs and thermal batteries can be cost-competitive with natural gas and that the former may have simple economic paybacks under two years, the cost of electrification remains a significant barrier to adoption.”

The Department of Energy offers incentives that can cut capital costs, but the report said additional federal and state funds are needed to drive electrification.

Power prices are higher than natural gas due to utility rate structures, which increase that difference during peak demand hours.

“These rate structures conflict with decarbonization goals and require policy intervention to reduce the cost of electrification and enable rapid deployment,” the paper said. “Thermal batteries, which can source electricity when it is cheapest, may circumvent the price gap barrier and deliver heat at or below the cost of heat from natural gas combustion.”

Buyers also have less confidence in the electric technologies due to their limited track record. The lack of experience extends to investors, which can translate into higher costs for projects.

“Buyers and investors must see more demonstrations and case studies featuring electrification projects across U.S. industrial applications to become confident in their operational and financial viability, thereby driving demand for these critical technologies,” the report said.

The technologies that can produce industrial heat and steam are in limited supply — as is the workforce that knows how to install and maintain them.

More Grid Resources Needed

Electrified processes also need renewable energy to decarbonize, with widespread electrification of industry potentially doubling demand for electricity. That presents an additional challenge for planners already struggling to transition the grid to cleaner resources.

“The slow pace of long-distance transmission construction and the long wait time for grid interconnections both present significant barriers to meeting increased electricity demand from electrification,” RTC said. “Long-distance transmission and a better-connected, cleaner grid would ensure that industrial facilities [could] access affordable, abundant renewable electricity to meet their needs and protect against outages.”

RTC has set a goal of cutting industrial emissions by 30% by 2030. New federal and state policies to fully electrify will be needed to hit that target.

Federal tax incentives can unlock project opportunities that would otherwise not be viable, and while the Infrastructure Investment and Jobs Act and the Inflation Reduction Act offer a bevy of subsidies for clean technologies, RTC said they were light on industrial decarbonization funding.

“To fill this gap, the RTC is educating members of Congress on the potential for electrification to decarbonize industry,” the report said. “We are also advocating for new investment tax credits to lower costs for industrial end users to electrify and expanded production tax credits that strengthen the economic case for manufacturers to increase supply. Because this will require new legislation, we are laying the groundwork now for action in 2025.”

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SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2024

SPP stakeholders approved congestion-hedging implementation policies last week, six years after first taking up the issue. 

“This may be a little more like Groundhog Day because we’re coming back once again with congestion-hedging improvements,” Evergy’s Jim Flucke said during the Markets and Operations Policy Committee’s virtual meeting. “The [Market Working Group] has been working on these improvements for probably about six years now. The Holistic Integrated Tariff Team [HITT] took it over for a while, but it came back to us. 

“We’ve worked very hard to find some compromise positions that satisfy the needs of those entities that aren’t getting congestion-hedging rights from their transmission that they’ve purchased. It is not everything that those entities had requested at the beginning, but after six years of work, it is a compromise between the two positions of not wanting anything and the desire to have more balance between market participants,” Flucke added. 

The revision request (RR591) would implement congestion-hedging policies already approved by the Board of Directors and Regional State Committee (RSC). 

MOPC Chair Alan Myers, with ITC Holdings, reminded stakeholders that the policies already have been decided to head off further discussion. 

“What we’ll be talking about today is implementation,” Myers said. 

The board and RSC approved a package of eight proposals, designed to increase equity, fairness and financial transmission rights awards among market participants, in July. (See SPP Board/Members Committee Briefs: July 24-25, 2023.) 

Since then, the MWG has added language for the annual long-term congestion rights (LTCRs) analysis performed during each round of the auction revenue right (ARR) nomination process to ensure nominated candidate ARRs do not violate any normal transmission-line thermal ratings under normal system conditions.  

The group also added language to distribute ARR surplus. This includes an iterative approach to the ARR allocation’s first round and the distribution of excess auction revenues. Once approved by FERC, SPP would allocate 50% of the excess revenue in one year under the old method and 50% under the new method. After that, the new process will take over. 

Terry Wolf, whose Missouri River Energy Services has filed a Section 206 complaint at FERC over the issue, said it still does not go far enough. 

“Given our situation of having long-term firm service that predated joining SPP and receiving zero LTCRs, we continue to believe it is unreasonable and not consistent with what the precedent is,” he said. “It’s taken too darn long, and it’s not turning quickly enough to provide equity to folks with long-term firm service. I continue to be frustrated by the lack of movement here.” 

MOPC Passes Plethora of RRs

MOPC approved 23 RRs and several other documents during the meeting. Myers told the Strategic Planning Committee on Jan. 18 that the agenda’s “volume of approval stuff” required members to “pound through pretty hard.” 

“Hopefully, better days are ahead as the rest of our meetings this year will be face-to-face,” he said. 

The endorsed revisions included: 

    • The Project Cost Working Group’s RR574, a response to concerns raised by stakeholders that SPP-issued upgrades were delayed past their need date and/or first reported in-service date. The PCWG and staff developed an in-service date delay report and a phased approach to improve transparency and situational awareness. A modified version of the RR that would have extended the original 90-day trigger for PCWG review to 180 days failed. “Extending this time to half a year is not going in the right direction,” the Advanced Power Alliance’s Steve Gaw said. “We should be adding some teeth to some of these cases.” The measure passed with 83% approval. 
    • The Transmission Working Group’s RR577, which clarifies the SPP flowgates that will be automatically included in the RTO’s initial constraint list; establish criteria for classifying facilities as economic needs because of congestion from planned or forced historical outages; and establish criteria for classifying facilities as reliability needs due to pre-contingency or post-contingent facility rating or voltage limit exceedances. 
    • RR578 passed unanimously with two abstentions. It creates a new and “appropriate” uninstructed resource deviation (URD). With an average cost to resources in 2022 of $3.65/MW of deviation proving not to be a sufficient deterrent for dispatch noncompliance, the MWG proposes the URD charge be equal to the real-time deviation above or below the resource operating tolerance multiplied by the absolute value of the real-time LMP. 
    • RR600.3, setting up rates for point-to-point and network service because of Western Area Power Authority’s Rocky Mountain Region and Upper Missouri region having facilities in both interconnections. The associated revenue distribution will be based on the amount of annual transmission revenue requirement specific to the facilities in an interconnection. The revision passed unanimously. 

Imports Help Weather the Storm

C.J. Brown, SPP’s director of system operations, told stakeholders that were it not for a record 6.8 GW of energy imports during the Jan. 14-17 winter storm, the RTO would have been in an energy emergency alert. 

“We almost got to [7,000 MW] … but 7,000 MW of imports during the storm, which is really impressive indeed, kept us out of an emergency,” he said, delivering an initial report on the event. “If you take away those imports, we would have 100% been in an EEA the entire time Sunday through Tuesday, no doubt about it. If you took away half those imports, we’re probably in an EAA, but we’re definitely on Sunday and Monday, maybe even Tuesday.” 

Some of the imports came from ERCOT on Jan. 14, attracted by higher prices in SPP. Power flows went in the opposite direction Jan. 15. 

The imports drew the attention of FERC Chair Willie Phillips during the commission’s open meeting Thursday. He said the storm underscored the importance of interregional transmission ties. 

SPP wound up setting a peak load record for January at 46.7 GW on Jan. 17, bettering the previous mark of 43.2 GW set in 2018. 

Brown said SPP experienced up to 20 GW of conventional resource outages during the event because of frozen coal piles and plant issues along the Missouri River. With wind “screaming” at times and producing 20 GW of energy at its high point, the grid operator was able to meet demand. 

“Things just do not operate well in -20 temperatures. They just don’t,” Brown said. 

McAdams to Consult with REAL Team

The leadership may have changed within the Resource and Energy Adequacy Leadership (REAL) Team, but it still is focused on addressing SPP’s resource adequacy corporate risk and goals, staff told MOPC. 

“It continues to be one of our corporate goals to mitigate this risk and move forward in a valuable and measurable manner for all of the various policies and initiatives we have going on,” SPP’s Casey Cathey said. 

Kristie Fiegen, chair of the South Dakota Public Utilities Commission, has replaced former Texas commissioner Will McAdams as the REAL Team’s chair. McAdams resigned from his posts in December. (See McAdams Honored During Last Texas PUC Meeting.) 

McAdams will remain involved with the team’s work. He has formed his own consulting firm, McAdams Energy Group, with a focus on energy and infrastructure development. The RSC already has contracted with McAdams’ firm to consult on mitigating the resource adequacy risk within the RSC and the REAL Team, SPP’s Kim O’Guinn said. 

Kansas Corporation Commissioner Andrew French has filled McAdams’ RSC seat on the REAL Team. To preserve the team’s regional balance, Texas Public Utility Commission senior economist Shawnee Claiborn-Pinto has replaced Kansas Corporation Commission staffer Shari Albrecht. 

Staff credited McAdams with the team’s success last year, which included developing and approving revision requests related to a winter season resource adequacy requirement (RAR) (RR549), performance based accreditation (RR554), and effective load-carrying capability (RR568), and demand response accreditation and fuel assurance policies; beginning an expected unserved energy (EUE) study and the load evaluation portion of the Future Energy and Resource Needs Study (FERNS); and completed the 2023 loss-of-load expectation study. 

This year, the team has set its sights on an “appropriate” accreditation of resources, winter season requirements, planning reserve margin (PRM) methodology changes, load forecasting and a future resource mix/EUE study.  

The workload includes addressing FERC’s November rejection of SPP’s proposed winter resource adequacy requirement. The commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781). (See “FERC Rejects Winter Requirement,” ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.) 

The commission said the proposal did not contain any requirement that a load-responsible entity’s (LRE) resources are expected to be available. It said SPP has not demonstrated it is reasonable to permit LREs to rely on resources that are not expected to be available in the winter season to satisfy their resource adequacy requirements. 

“They gave us very tangible feedback,” Cathey said. “From a staff perspective, we have not lost effective dates such that we can still move the ball forward with the winter PRM.” 

SPP plans to refile the winter RAR at FERC in April. If approved, it will be nonbinding until the 2026-27 winter. 

The REAL Team begins its slate of meetings with a virtual meeting Friday. 

2 Items Pulled off Consent Agenda

Members pulled two revision requests off the consent agenda for individual votes but ended up approving both.  

Renewable energy interests asked for more transparency into the calculations of RR603, which increase study deposits for new generator interconnection requests using FERC Order 2023’s mandated schedule and adds a non-refundable application fee. The change also increases deposits for surplus, modification and replacement studies. 

Staff said a survey of the last seven study clusters indicated costs generally are 10 to 30% more than the current maximum study deposit of $90,000. Under the Order 2023 schedule, most deposits will range from $100,000 to $150,000 and would have covered the average costs for the clusters, they said. 

“I’ve asked for the documentation,” Gaw said. He acknowledged SPP has said the study costs are correct but said, “There’s been some degree of concern about how these things have been handled, on the amount of the consultants that have been used and how contracts are done.” 

Steve Gaw, APA | © RTO Insider LLC

Although the revision passed the Regional Tariff and Transmission Working Groups with just one abstention, staff said they have responded to stakeholder concerns by implementing a request-for-proposal process for special studies; reached out to SPP-approved consultants for pricing and availability; added consultants to the study pool to increase diversity and competitive costs; and performed special studies in-house when resources are available. 

MOPC endorsed RR603 with 85.1% approval. 

The committee also separately approved a remedial action scheme (RAS) in western North Dakota with a near-unanimous vote. The RAS will provide temporary relief in the Williston load pocket until the Roundup-Kummer Ridge 345-kV line is completed early next year. 

Flucke expressed concern over the proposal, saying it is causing TCR underfunding. 

SPP’s Micha Bailey said the RAS will help TCR underfunding because it loosens as the impact of that congestion constraint decreases. “That’s going to lessen the amount of congestion on that [region], which then was the amount of money owed to those TCR holders.” 

MOPC’s consent agenda included 15 RRs, five of which (RR600.1-RR600.6) are related to western entities integrated into SPP’s RTO. It also included approval to retire the Thunderhead RAS in Nebraska in November; a lessons-learned report on the third Regional Cost Allocation Review; the 2024 Transmission Expansion plan; the 2023 Integrated Transmission Plan’s (ITP) short-term reliability project report; and a 2024 ITP market powerflow models waiver. 

The RRs would: 

    • RR560: Move operating criteria language to the system operating limits (SOLs) methodology.  
    • RR583: Allow SPP to nominate LTCRs for federal service exemption and grandfathered agreements carveouts to further mitigate load’s exposure to the day-ahead market’s (DAMKT) congestion costs. 
    • RR587: Correct the virtual energy offer curve from 0 to 100 MW to accurately reflect current pricing. 
    • RR588: Modify the regulation-selection process to include qualified resources that cleared regulation in the DAMKT for the operating hour, reducing their financial risk to competitively offer ancillary services in both the day-ahead and real-time markets. 
    • RR593: Clarify the cost allocation for two Basin Electric substations so that both can correctly be allocated according to the base plan. 
    • RR594: Incorporate improvements mandated by FERC Order 2023 to ensure the generator interconnection process is just, reasonable, and not unduly discriminatory or preferential. 
    • RR595 Close a market design gap related to FERC Order 831’s implementation by using make-whole payments to compensate resources being unable to recover their cost of incremental dispatch in some scenarios. 
    • RR597: Document the DAMKT high-level process used for effective limit application. 
    • RR598: Remove planning criteria portions outlining the methodology to develop SOLs and interconnection reliability operating limits (IROLs) in the planning horizon. This aligns with NERC’s retirement of Mandatory Reliability Standard FAC-010-3.  
    • RR600.1: Clarify for western parties integrating into SPP’s RTO terms and conditions that Attachment AU, which describes the distribution to transmission owners of revenue received from MISO under a settlement agreement, applies to TOs in the Eastern Interconnection. 
    • RR600.2: Include existing non-radial lines, substations and associated facilities operating at 100 kV or above, and radial lines and associated facilities operated at or above 100 kV that serve two or more eligible customers that are not affiliates of each other as transmission facilities in the West under Attachment AI.  
    • RR600.4: Remove Attachment AT and its definition of a contract services agreement between Basin Electric Power Cooperative and SPP, which no longer will be needed with Basin’s integration into SPP’s western RTO. 
    • RR6005: Modify the tariff to refer to a WAPA division where it currently refers to WAPA-Upper Great Plains. 
    • RR600.6: Revise Attachment S, under which transmission providers determine megawatt-mile impacts separately for the SPP East Region and SPP West Region, to also include SPP Region, if needed. Because WAPA’s Upper Missouri and Rocky Mountain Region zones having facilities in both interconnections, some rates for point-to-point and network service and their associated revenue distribution will be based on the amount of annual transmission revenue requirement specific to those facilities in an interconnection. 
    • RR601: Ensure multiday minimum runtime RRs and clean-up RRs (RR382, RR540 and RR569) are accurately implemented and functioning as designed. The revision creates new determinants to represent the effective start-up amount of a resource that will only be used in the evaluation of the day-ahead and real-time multiday minimum run time make whole payment.