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December 22, 2025

MISO Pledges Work on Affected System Studies

MISO said last week that it will approach SPP about improving the processes underpinning affected system studies in response to stakeholders’ persistent calls for change.

Stakeholders participating in an Interconnection Process Working Group teleconference on Jan. 12 again questioned why SPP affected system studies include such strict deliverability requirements for MISO generation seeking to interconnect within MISO’s footprint. (See MISO West Risks Becoming ‘Dead Zone,’ Stakeholders Warn.)

The MISO and SPP affected system studies processes often produce prohibitively expensive transmission upgrades for prospective generation projects near the seams and interfere with developers’ ability to judge the commercial viability of proposed generation.

“I think we’ve all seen the FERC proceedings and the issues, but these problems aren’t going away. And I don’t say this is MISO’s problem. We’re all in this together,” EDF Renewables’ Arash Ghodsian said.

Coordination between the affected system studies needs another look, Apex Clean Energy’s Richard Seide said.

“We’re definitely here to see how we can improve. We’re all ears,” MISO Principal Resource Interconnection Planning Engineer Sumit Mundade said.

“Why does SPP study a MISO resource as if it’s a SPP resource at all?” Michigan Public Service Commission staff member Bonnie Janssen asked.

Mundade said the idea is to figure out whether generators in the MISO footprint could harm SPP system performance.

Apex Clean Energy’s Deepesh Rana asked if MISO could give interconnection customers earlier notification on what projects will face additional upgrade costs in light of SPP’s study findings.

“Is there something that could be done to give more frequent communication on where the analysis stands, in a non-binding way?”

Mundade said SPP recently changed its process to use a screening analysis to identify the specific projects it will study “instead of the old process of studying the whole cluster.”

He said MISO can speak with SPP about providing earlier notice on the generation projects selected for affected system studies, but it’s unlikely to able to provide earlier cost estimates for the network upgrades SPP identified.

The two RTOs could discuss the possibility of earlier notification and other affected system study process improvements during their monthly nonpublic interregional staff meetings.

Stakeholders also asked MISO to discuss study improvements in the context of its new interregional transmission study, which aims to alleviate the RTOs’ respective queue bottlenecks. (See MISO, SPP to Conduct Targeted Transmission Study.)

“If MISO doesn’t discuss in joint meetings how this can be addressed in the joint study, then I think that’s an opportunity missed,” Customized Energy Solutions’ Ginger Hodge said.

Shortened Queue Still MISO’s Goal

Meanwhile, MISO plans to file a proposal to reduce the timeline for a key portion of its interconnection queue — from the definitive planning phase to the signing of an interconnection agreement — to a single year. (See “Queue Timeline Cutbacks Still in the Works,” MISO Winds down MTEP 20 Planning, Focuses on 2021.)

MISO Affected System Studies
MISO’s current interconnection queue | MISO

“The goal is to cut almost 140 calendar days from the current process,” interconnection study engineer Miles Larson said.

Larson said the truncated timeline is set to begin with the 2022 cycle of prospective generation. MISO will achieve the reductions by cutting the days allotted for interconnection agreement negotiations and study, performing some study aspects simultaneously.

“Before, the process was very sequential. A lot of these tasks can now be done in parallel,” he said at a meeting in November of the Interconnection Process Working Group. He added that study assumptions and modeling will remain unchanged.

But by the end of last year stakeholders were skeptical MISO could achieve those efficiency gains without speedier processing of affected system studies with neighboring RTOs.

“The focus is how do we build these models faster? How do we run these studies more efficiently? How can we be more transparent?” Larson said during the interconnection meeting in January. “Without challenging our timeline, we’re not going to get more efficient processes or an alignment” between studying network upgrades and annual transmission planning. (See MISO Begins Bid to Merge Tx, Queue Planning.)

At the Planning Advisory Committee meeting Jan. 13, MISO Senior Manager of Economic Planning Neil Shah said it would be nearly impossible to evaluate generator interconnection upgrades for wider economic benefits “within the current definitive planning process framework and timeline.”

Larson said stakeholder feedback from the 2022 cycle of projects will be used to make further revisions to the timeline if necessary.

But some said affected system studies remain the real stumbling block to achieving a swifter interconnection process.

“I think affected studies are always going to hold this process back,” Ghodsian said. “I would encourage you to work with your neighbors. … I think you can share your ideas with SPP and PJM as they’re in the early stages of addressing their queue backlogs.”

MISO counsel Mike Blackwell agreed that affected system studies remain a “big concern.”

The RTO’s interconnection queue currently contains 628 projects totaling 93 GW, enough to cover about three quarters of total load on a peak summer day.

Baker Vetoes Mass. Climate Bill

Massachusetts Gov. Charlie Baker (R) vetoed a wide-ranging climate bill Thursday, saying he needed more time to scrutinize the details of the legislation and recommend changes.

“While I support the bill’s goals and am largely in agreement with many of its proposals, 35 hours was not enough time to review and suggest amendments to such complex legislation,” he wrote in a letter to lawmakers explaining his decision.

The bill, which overwhelming passed both the state House and Senate, was sent to Baker’s desk just before the end of the two-year legislative session and would have provided the state another path to reach net-zero carbon emissions by 2050.

The law would have required Massachusetts to reduce emissions to 50% below 1990 levels by 2030, 75% by 2040 and 85% by 2050. It also called for utilities to procure an additional 2,400 MW of offshore wind power, raising the state’s total to 5,600 MW. (See Mass. Lawmakers Pass Sweeping Climate Law.)

Baker recently released his own legally binding plan to achieve net-zero emissions in the same time frame, and additionally joined with Connecticut, Rhode Island and D.C. in launching the Transportation and Climate Initiative Program (TCI-P), which aims to cut greenhouse gases from vehicles and invest in cleaner transportation choices and public health improvements. (See NE States, DC Sign MOU to Cut Transportation Pollution.)

Among the specific reasons Baker cited in his veto was the climate bill working against recently enacted Housing Choice legislation. He added there is “nothing in this bill to adapt to the ongoing and future impacts of climate change.

Massachusetts Climate Bill
Massachusetts Gov. Charlie Baker | © RTO Insider

“If we intend to comprehensively address climate change, we must give ourselves and our colleagues in local government the tools necessary to create a Commonwealth that is more resilient to the destructive weather events and natural disasters we continue to face because of ongoing climate change,” Baker said.

The governor said that while his administration “wholeheartedly supports the environmental justice goals of this bill, intent without the tools to address those issues are empty promises.”

The Union of Concerned Scientists (UCS) said Baker’s veto was an “unnecessary and disappointing move.” It said the legislation would have strengthened the state’s carbon emissions goals.

“A lot of really good thinking from a whole lot of perspectives went into shaping this bill, and it has so many important pieces,” said Paula García, senior bilingual energy analyst at UCS.

“The governor said he vetoed the bill in part because it would slow housing production. This is a false choice,” she said. “We can address climate change and housing needs simultaneously.”

According to a UCS study, about 7,000 residential properties, currently home to roughly 14,000 people in Massachusetts, are at risk because of rising sea levels by 2045. The total number of at-risk residential properties jumps to more than 89,000 — 178,000 people — by 2100.

“While Massachusetts has a network of shoreline stabilization structures along its coast, few of these are designed to keep out higher tides,” García said. “And we know that people of color suffer disproportionately from climate impacts.”

She said Baker’s action “is a horrible lost opportunity to stop perpetuating environmental injustices.”

“Being a whole lot bolder about our climate trajectory is something we need now,” García said. “Faster clean energy progress is incredibly important — for addressing our enormous public health challenges, getting the economy back on track and making sure that we’re bringing every tool to bear to dismantle systemic injustices.”

Dan Dolan, president of the New England Power Generators Association (NEPGA), said his organization “strongly supports the need for collective, economy-wide action to meet the climate challenge.”

“A reliable, cost-competitive and clean electricity grid is vital to driving deep decarbonization across the economy, and New England’s competitive electricity generators stand ready to power that future,” Dolan said. “Now is an opportunity to revisit a bill passed in the waning hours of an unprecedented legislative session.”

He added that “to most efficiently drive carbon reductions, the legislature should enact a meaningful, multisector price on carbon emissions.”

“This focus on the actual cause of climate change can create a sustainable and durable marketplace to meet our climate responsibilities,” Dolan said. “NEPGA urges the legislature to focus on this approach and not continue its reliance on decades-long contracts that undermine the innovation, competition and consumer benefits of the New England-wide electricity market.”

‘Clarion Call’

Baker told the legislature his administration does not want to choose “clean energy winners and losers” and should “let resources compete in a manner that delivers the most benefit at the least cost to Massachusetts ratepayers.”

In October, Baker, along with governors from Connecticut, Maine, Rhode Island and Vermont, jointly released a statement arguing that New England Governors Call for RTO Reform.)

Baker told legislators that he wants to “allow this process to reform our regional energy system to mature over the coming months, at which point we will better understand whether further state procurements are necessary, or if opportunities for regional procurements and coordination emerge as a more effective approach to secure clean energy resources while protecting Massachusetts ratepayers.”

Dolan said that portion of Baker’s letter goes directly to the broader point NEPGA has been raising regarding the impact of long-term contracts.

“NEPGA applauds Gov. Baker’s clarion call to drive the next evolution of the regional electricity market to meet the clean energy and climate needs of New England while preserving reliability through competitive markets,” he said.

Dolan said NEPGA is committed “to engaging with the states to shape the future of the electricity market,” and it urges Massachusetts lawmakers to do the same with their regional counterparts.

“The efficiency and cost gains by pursuing this regional vision is consistent with scores of reports and analysis from academic and industry experts — and the states themselves,” he said.

Concluded García: “Massachusetts can and should do more, and we need to be as bold as we can be. With the speaker of the House and the Senate president committed to reintroducing the legislation, we’re not back at square one on this legislation. But at this point, we should be across the finish line.”

Calif. PUC Orders $200M Microgrid Incentive Program

The California Public Utilities Commission ordered the state’s investor-owned utilities to take steps to hasten the creation of microgrids Thursday, including establishing a $200 million incentive program for communities most at risk from public safety power shutoffs (PSPS).

It was the latest in a series of measures the commission pushed through in the past year in an effort to mitigate impacts when utilities intentionally shut off power to prevent electrical equipment from igniting wildfires. (See Calif. Rushing Microgrids for Fire Season Shutoffs.)

“This decision is the culmination of a whirlwind year … for microgrids and the resiliency team,” CPUC President Marybel Batjer said. The commission issued two major decisions in one year when a single decision generally takes 18 months, she said. “This has been nothing short of a whole lot of hard work done very quickly.”

The commission unanimously approved a proposed decision on Track 2 of their microgrid rulemaking to facilitate local generation and distribution that can operate independently of the larger grid in emergencies. It ordered the state’s three large IOUs — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to each adopt new microgrid tariffs and to collectively create a $200 million program to incentivize microgrids in underprivileged communities that are most vulnerable to PSPS.

California Microgrid
The Blue Lake Rancheria in Humboldt County installed a microgrid to provide power during PSPS. | Siemens

“This decision builds on our efforts to reduce barriers for the commercialization of microgrids while keeping an eye to ratepayer equity and supporting vulnerable and low-income communities,” Commissioner Genevieve Shiroma, who led the effort, said in a statement.

The adoption of microgrids was fast-tracked by Senate Bill 1339, passed in 2018. The bill requires the CPUC to implement microgrid standards, rates and tariffs, and reduce barriers to microgrid deployment.

The commission retooled its rulemaking to focus on microgrids and resilience ahead of the 2020 fire season. It established a new section in its Energy Division devoted to the matter and opened the rulemaking in September 2019.

In Track 1 of the rulemaking, the commission ordered IOUs to streamline and expedite interconnection processes for microgrid resilience projects and to work with local and tribal governments to bring the projects online by late summer 2020. The plan called for utilities to standardize application processes for microgrids, to expedite signoffs on installed projects and to increase staffing to accelerate interconnections. (See CPUC Proposal Would Promote Microgrids.)

The CPUC also approved controversial plans by PG&E to deploy hundreds of diesel generators to power substations and key facilities for the 2020 fire season. It expressed dismay at the idea of using diesel fuel amid the state’s push for clean energy but said it was the only immediate solution to widescale power outages.

Track 2

Dozens of parties commented on the Track 2 decision. Some argued it placed the development of microgrids in the hands of the large IOUs responsible for starting wildfires instead of letting affected communities have more input.

“We urge the commission to reject the current proposed decision and to include the voices of Black, indigenous and people of color in making revision to the proposed decision that will include control and ownership in development of these resources in those communities,” said Barbara Stebbins, a member of San Francisco Bay Area advocacy group Local Clean Energy Alliance’s steering committee. “The current proposed decision gives almost complete control over microgrid development to the investor-owned utilities,” which runs contrary to the intent of SB 1339, she argued.

The commission shared those concerns but praised the decision’s incentive program, which it said would lessen the likelihood that wealthier communities would have their own backup power while poorer communities would not.

“I appreciate the caution that’s taken in looking at how these rule changes and potential tariff changes will impact the entire rate base,” Commissioner Martha Guzman Aceves said. “I actually appreciate the incentive approach in order to guard from leaving the customers behind who probably need it the most, certainly in the scenario of a PSPS event.”

The commission also told utilities to find clean energy approaches to backup power by 2022 to replace the diesel generators.

“This decision addresses resiliency to keep customers energized for the upcoming 2021 fire season, including a transition plan to clean backup generation for 2022 and beyond,” Shiroma said. “We will continue to actively engage with stakeholders to make the grid more resilient for all.”

NYISO Business Issues Committee Briefs: Jan. 13, 2021

NYISO’s Business Issues Committee on Wednesday approved manual revisions related to Tariff revisions submitted to FERC last month.

Michelle McLaughlin, senior settlements analyst, presented the revisions to the Revenue Metering Requirements Manual (RM2) and Meter Services Entity Manual. They reflect changes that allow market participants representing day-ahead demand response and demand-side ancillary services program resources to use meter services entities (MSEs) until those programs are eliminated in 2022.

NYISO’s distributed energy resources participation model permits an MSE to provide meter services and meter data services to responsible interface parties (RIPs), curtailment service providers (CSPs) and aggregators. (See NYISO OKs Changes on Hybrid, Fast Start Resources, TCCs.)

FERC in January 2020 approved Tariff changes permitting RIPs and CSPs to utilize MSEs for demand-side resources.

“In December we filed the Tariff modifications with FERC and we’re hoping to implement this in February as soon as the Tariff modifications become effective,” McLaughlin said.

Updating 2019 CARIS Database

NYISO must update and extend the 2019 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 database for specific project evaluations under 2020 CARIS Phase 2 studies. It presented related material to stakeholders for discussion.

NYISO Business Issues Committee
Projected demand congestion by constraint ($M) | NYISO

“The database itself will not differ much at all between what we have here and what we’ll have for the 2021 System Resource and Outlook study pursuant to the recent stakeholder-approved enhancements to the economic planning process,” Manager of Economic Planning Jason Frasier said. “The real change is more in the process, not so much in the underlying data.”

The ISO will soon file Tariff revisions to streamline its economic transmission planning and expand its scope to capture the grid’s ability to deliver energy from the future generation resource mix to the forecasted load. The changes rename the CARIS Phase 1 study to the System and Resource Outlook and double the assessment periods to 20 years. (See “OKs Economic Planning Changes,” NYISO Business Issues Committee Briefs: Dec. 9, 2020.)

“The changes expand the original 10-year timeframe of 2019 to 2028 to cover the next 10 years out to 2038,” Frasier said.

The 2020 CARIS Phase 2 base case will be used for evaluating specific Regulated Economic Transmission Projects (RETP) as required under the Tariff.

Senior planning engineer Chen Yang said key updates to New York Control Area (NYCA) generation status reflect the compliance plans generators submitted in response to the state’s Department of Environmental Conservation “peaker rule,” new NOx regulations that go into effect May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

“It’s worth mentioning that the service pattern in the last two columns [on the right] — basically May 2025 to September 2025 and October 2025 to April 2026 — are repeated for the subsequent years in the CARIS study period,” Yang said.

NYCA network model assumptions include:

  • Leeds Hurley system deliverability upgrade in-service in summer 2021;
  • Cedar Rapids transmission upgrade in October 2021;
  • L33P (Ontario PAR) out of service until January 2022, and then modeled back in service;
  • Empire State Line Project/Western New York Public Policy Need project in-service in January 2022; and
  • AC Tx Public Policy projects in service in January 2024.

    NYISO Business Issues Committee
    NYCA generation key updates modeled status changes in compliance with the DEC peaker rule. | NYISO

Planners adjusted some dates because of software limitation, so the dates used for the study may not reflect actual, expected in-service dates.

Demand congestion would be reduced by the introduction of the AC transmission projects and associated upgrades starting in 2024, Yang said.

Any subsequent updates to the 2020 CARIS Phase 2 Base Case would be brought back to stakeholders for further review.

SPP Wind Output Rises to Record 19.9 GW

It took all of two weeks into the new year before SPP set new peak records for wind and renewable energy output.

The RTO on Thursday upped its historical highs for wind and renewable energy to 19.9 GW and 21.2 GW, respectively. Those marks broke records set late last year of 19.7 GW and 20.9 GW, respectively.

SPP Wind
SPP’s latest peak records for wind, renewable energy. | SPP via Twitter

“An incredible amount of wind generation in our region, all without sacrificing reliability of the grid,” SPP CEO Barbara Sugg tweeted.

Maybe not that incredible, given that wind served 31.3% of SPP’s load last year. The grid operator said that made it the first U.S. RTO or ISO with wind as its No. 1 fuel source.

ERCOT, SPP’s primary competitor in the wind race, saw wind energy meet 22.8% of its load last year, second only to natural gas (45.5%). The Texas grid operator, which meets about 50% more demand than SPP during summer months, also set a record Thursday with 22.9 GW of wind generation.

SPP set six records for wind production in 2020 and four records for renewables. In April, the RTO established a record when wind served 73.2% of load for one interval. (ERCOT’s record for a single interval is 59.3%.)

The grid operator has 26 GW of installed wind capacity on its system, and another 39.9 GW of proposed projects are under some form of study in its generation interconnection queue.

ERCOT has 31.7 GW of installed wind capacity.

MISO Begins Longterm Tx Modeling

MISO will draw on its new planning futures to build the first set of models that could result in its long-term transmission plan’s first projects.

The RTO’s senior manager of system planning coordination, Jarred Miland, said staff are building reliability and economic models similar to those used in MISO’s annual Transmission Expansion Plan (MTEP). He said the long-term assessment’s first models will be ready for member review during 2021’s first quarter.

The models will be based on three MTEP futures designed for use in the 2021 planning cycle and beyond.

Late last year, MISO launched its first long-term planning effort in a decade to connect fast-growing renewable sources with load centers. (See MISO Prepares Members for Pricey Transmission Expansion.)

MISO Transmission
| © RTO Insider

Miland said during Thursday’s Planning Advisory Committee that staff will use the more conservative Future I to build seven base reliability models each for 2030 and 2040. The future assumes 85% of utilities’ carbon-cutting plans are met and carbon is reduced 40% from 2005 levels by 2040. MISO currently operates at a 22% carbon reduction from 2005 levels.

“If you think about it, there are over 100 models we could build and we could spend months and months building models and never get to the analysis,” he said. “That’s not to say we won’t build more models. In fact, I expect we will build more models. But we needed something to begin analysis with. … These 14 models certainly won’t be the end-all.”

Miland said Future I modeling simply kicks off work that will take place in 2021. He emphasized that the long-term planning will take place over several transmission cycles and said that MISO will also likely build seven models apiece for the more aggressive Futures II and III.

“This a long-term plan to see how we’re going to stay ahead of the game for the next 40 years,” Miland said. “We do anticipate that at end of this year, we may have some projects with ripe business cases that we can bring forward for board approval.”

While MISO focuses on model builds, the Organization of MISO States is concentrating on how the long-range projects’ cost might be shared in the footprint.

The OMS convened a special cost-allocation committee late last year to draw up principles on how MISO should approach long-term projects’ cost sharing.

Up until approval, OMS members were wrestling over whether states with more aggressive clean-energy policies should bear a greater share of the costs for transmission that enables renewable energy.

Some commission staff pointed out that several states with renewable portfolio standards have already exceeded their targets. Others said it remains to be seen whether MISO will consider public policy requirements as a benefit metric. The staffers also debated whether some transmission costs should be allocated on a postage stamp basis and whether some long-term transmission projects should be packaged into portfolios.

MISO has said projects will likely face approval independently in annual timelines, rather than being approved en masse in a portfolio.

Speaking at an OMS cost-allocation principles meeting Jan. 11, Minnesota Public Utilities Commissioner Matt Schuerger said bundling transmission projects that have “synergies” can sometimes make sense. He said it’s not as if planners would lump together transmission projects “from opposite ends of the footprint.”

But New Orleans City Council attorney David Shaffer said each transmission project should be able to stand on its own under scrutiny.

NYC’s Largest Generator Has New Name, New Aim

LS Power subsidiary Ravenswood Generating, which runs the largest power plant in New York City, announced on Thursday that it will change its name to Rise Light & Power and expand to develop large-scale clean energy projects.

The company will continue to operate the 2,480-MW Ravenswood Generating Station, the steam energy power plant in service since 1963 on the East River waterfront in Queens. The plant represents over 20% of installed capacity in NYISO’s Zone J.

The company’s first new large-scale project is the Catskills Renewable Connector, a 1,200-MW submarine and underground transmission line to connect its site in New York City with Greene County on the western side of the Hudson River and just south of the capital region.

“We’ll be able to unlock shut-in wind and solar across upstate that previously hasn’t been able to reach customers in New York City,” Rise Light & Power CEO Clint Plummer told RTO Insider. “Obviously it’s got to be done in locations where there’s community support for development, and we think there’s a lot of that.”

The state the previous day issued a solicitation for transmission projects to bring renewable energy from upstate and Canada to New York City as part of Tier 4 of its Clean Energy Standard, with planners hoping the transmission “arteries” will feed a 250-mile, $2 billion green “superhighway” project. (See “Other Projects,” NY Awards 2.5-GW Offshore Deal to Equinor.)

The company has filed a NYISO interconnection request (No. 1120) but has not yet committed to a path for financing and regulatory approval of its new transmission line.

Roads to Reality

“We think there are a number of different ways we could get the revenue support that we need,” Plummer said.

New York has quickened its permitting processes for both renewable siting and so-called priority transmission projects. Does Plummer think the company can get this new project under construction faster than the 10 years typically needed?

“Possibly, and I say possibly because some transmission lines have taken a long time, others take less time,” he said. “For any type of big infrastructure project, it needs to be planned in close coordination with the communities, and we need to be engaging and listening to the thoughts and concerns of those communities and developing routes that work best for them. New York has a very efficient process for evaluating and granting permits to large-scale transmission projects under Article VII, [the state law governing project siting], but that same process also allows for a great deal of stakeholder input, and that’s a good thing.”

The company also has potential to redevelop Ravenswood’s 28-acre site without adversely affecting the existing generation, Plummer said. Since acquiring the plant in 2017, LS Power has invested more than $160 million in modernization and resiliency upgrades for the facilities and removed more than 300 MW of fossil-fired peakers from service.

The state’s Public Service Commission in 2019 approved construction of a 316-MW battery storage facility in three phases on the site. The first phase was scheduled to come online this year, but the company on Tuesday filed a request to extend the Phase I completion date from April 2021 to June 2024 (19-E-0122). (See “Largest Storage Project in New York,” NYPSC Projects Lower Winter Energy Prices.)

The PSC on Sept. 17 modified dynamic load management implementation plans for the state’s six investor-owned utilities, all related to storage, saying the initial plans “resulted in a bias towards short-term, low-capital investment solutions” because of their yearly performance structure (18-E-0130). (See NY Utilities, Developers Tweak Storage Procurement Terms.)

The commission’s December 2018 storage order required Consolidated Edison to procure at least 300 MW of storage capacity and each of the other utilities to procure at least 10 MW each, with assets to be operational by Dec. 31, 2022, on contracts up to seven years.

“While LS Power has an impressive track record developing merchant energy storage in California, the New York market does not currently support that kind of development, so the economic viability of this storage project depends upon us obtaining a contract with a customer like Con Edison or NYSERDA,” Plummer said. “We participated in Con Edison’s 2019 solicitation, and at the end of this past year we found out that we lost.”

Con Edison will run another solicitation in 2021 and Plummer said his company looks forward to participating and hopes to win.

Plummer served on the planning team at Deepwater Wind that developed the Block Island offshore wind farm and takes hope from that experience.

“We proposed the project in 2008, and it took us until 2016 until it was built, and of that eight-year period, six of it was getting all the permits, approvals and public support in place,” he said.

NYISO Explores Improving BSM Processes

NYISO on Tuesday proposed updating its buyer-side mitigation (BSM) processes in order to compensate for the growing disconnect between the original design, intended to cover a few new resources in any given class year, and the up to 50 such resources to be evaluated currently.

The ISO’s BSM rules are designed to prevent uneconomic entry of subsidized resources into its markets. It expects the number of resources needing to be studied under the rules to increase by five to 10 times the historical norm, while the two-year period formerly allowed for these evaluations has halved, Shaun Johnson, director of market mitigation and analysis, told the Installed Capacity Working Group (ICAPWG).

“We’re adding several other BSM evaluations, which could result in at least four to six BSM studies per year, certainly for 2021,” Johnson said. “We’re in the process of wrapping up the studies for Class Year 19, hopefully very soon. … So, just in the next six months, we could be looking at an additional four to six studies.”

NYISO BSM
The 2-MW Lewis County Solar Project in Lowville, N.Y. NYISO is seeing a surge of renewables seeking to interconnect, potentially overwhelming its BSM study processes. | Lewis County, N.Y.

Until recently, staff usually performed the BSM process on about five resources over the course of a class year. CY17 had about seven resources evaluated for BSM, Johnson said. CY19 had more than 50 resources at the start of the study.

“The current processes were not designed to be able to be administered effectively under this expected work load,” Johnson said.

Input Assumptions

“This initiative will not discuss new BSM designs or exemptions to BSM; there is a separate process underway with the ISO, the Comprehensive Mitigation Review,” Johnson said. “We’re all really uncomfortable right now about the risks that the BSM process in particular can add to the delays of the class year timeline.”

Those delays could stem from determining the assumptions that go into energy and capacity price forecasts, which determine whether new market entrants are subject to certain exemptions. Part A exempts a new resource from BSM if the forecast of capacity prices in its first year of operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years is higher than the resource’s net cost of new entry.

NYISO has appealed NYISO Appeals FERC Rejection of BSM Proposal.)

“When you have four or five resources that you’re looking at, you can iterate and say, ‘if this one’s out, this is the effect it’s going to have’” on prices. “But when you have 30, 40, 50 resources, you just can’t iterate like that,” Johnson said. “The time it would take to do that is inconceivable, particularly when we get down to the [installed reserve margin] and [locational capacity requirement] values.”

NYISO wants stakeholders to consider the timing and lockdown of input assumptions, such as whether it should allow for discussion of the inputs with stakeholders, or post rough assumptions well in advance, Johnson said.

One stakeholder urged the ISO to balance the need for market fairness with the desire for administrative efficiency, urging staff not to avoid extra calculations if they are needed.

NYISO BSM
The 340-MW Alle-Catt Wind Farm is being built near this Amish family farm south of Buffalo. | Joed Viera

Tariff Clarity

NYISO also wants to add language to clarify how the limit on exemptions for renewables is calculated, as the tariff often can be unclear, Johnson said. The ISO had wanted to limit renewable exemptions in a class year to 1,000 MW of installed capacity, but FERC rejected that. It later accepted a proposal to use an unforced capacity reserve margin impact component in the renewable exemption limit formula. (See NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)

“This was the first time we applied the renewable exemption limit that we just filed and got approved … and we realized as we’re administering the provisions that were written that some of them we didn’t write well,” Johnson said. “Others are not consistent with what we presented to stakeholders; they are consistent with what we described in the filing, but we do want to circle back on those components and discuss with stakeholders whether we want to update and clarify this or not.”

The ISO also wants to revise language addressing the inclusion of units, supply stack inclusion rules and inflation rate terminology, he said.

NYISO is requesting feedback by Jan. 27 in order for stakeholder comments to be included in any specific enhancement proposals Johnson plans to make, ideally, at the Feb. 9 and Feb. 25 ICAPWG meetings.

Regardless of changes in the composition of FERC under the incoming Biden administration, the next steps are to develop a proposal in time for the Business Issues and Management Committees to consider at their April meetings, Johnson said.

3rd Comment Round Begins for AVR Standard Proposal

NERC on Thursday opened a third formal comment period on the standard authorization request (SAR) for Project 2019-04 (Modifications to reliability standard PRC-005-6) following revisions by the drafting team aimed at addressing criticism received during the second round that closed in July.

Many respondents had indicated surprise at the proposed changes to PRC-005-6, which requires utilities to “document and implement programs for the maintenance of all protection systems, automatic reclosing and sudden pressure relaying affecting the reliability of the bulk electric system.”

Objectors included the North American Generator Forum (NAGF), which submitted the original SAR in May 2019 with the goal of clarifying the standard’s applicability to automatic voltage regulators (AVRs). (See AVR Standards Team Faces Industry Pushback.) In a comment endorsed by several other participants, the organization said the proposal had “evolved into a draft that the NAGF can no longer support” and requested that the drafting team “revert back to the original SAR as previously submitted.”

AVR Proposal
Automatic voltage regulator

Team Tries to Calm Overreach Fears

According to NERC’s unofficial comment form, stakeholders are asked to respond to the following questions:

  • Does NERC’s current definition of “protection system” create confusion with regards to protective functions embedded in control systems, as it omits protective functions in the excitation and other control systems?
  • Should BES protective functions that respond to electrical quantities inside excitation systems be included in PRC-005, along with BES protective functions inside other control systems?
  • Should PRC-005 provide for the use of alternative protection system station DC supply technologies, whether battery-based or not, and ensure that they are subject to maintenance requirements?
  • Should entities registered as under-frequency load shedding-only distribution providers be considered as functional entities applicable to PRC-005?
  • Are there any logistical or cost considerations that would add significant burden to equipment owners trying to confirm protective functions in an exciter, inverter or other control system, and are there more cost-effective solutions that the drafting team could consider?

These questions are largely identical to those in the last round, with the exception of the third, which substitutes “alternative” for “emerging.” However, the new draft SAR incorporates changes outlined by the drafting team in a previously published response to the industry objections.

Most of the criticism that the second draft received focused on respondents’ perception that it represented an unwarranted expansions of the project’s goals, particularly in its attempt to apply PRC-005 to control systems. As a result, the drafting team devoted a significant portion of its response to explaining why it believes such changes are needed and do not constitute overreach.

“The SAR drafting team does not intend to state that non-BES protective functions, such as those detecting malfunctions of the excitation system, are within the scope of PRC-005,” the team said in its comment on the definition of “protection system,” emphasizing that the expanded definition is meant to clarify that AVRs are included.

Similarly, the team’s approach to the second question focuses on the lack of clarity regarding BES protective functions in the current version of PRC-005. The drafting team was concerned that “only addressing traditional synchronous generator excitation systems was not fully addressing the potential reliability gaps in the interpretations of PRC-005 applicability to protective functions in all control systems.”

In response to industry objections, however, the draft SAR has been updated to emphasize that the standard will be applicable only to BES protective functions, meaning that protective functions inside excitation and control systems that do not “perform as a BES protection system” would not be included. The team also promised that industry comments will be forwarded to the future standard drafting team once the SAR is approved.

Other changes include clarifying that battery energy storage systems are not being considered for inclusion in PRC-005, and that the SAR’s mention of battery technologies is because DC supply technologies, whether they include batteries or not, are not currently included in the standard’s maintenance requirements. This came in response to a comment from Edison Electric Institute that said it was “unclear” whether the current standard already addressed such equipment.

Comments on the revised draft SAR are due by 8 p.m. Feb. 12.

NY Awards 2.5-GW Offshore Deal to Equinor

New York on Wednesday announced that it is awarding 2,490 MW in offshore wind contracts to Equinor Wind US, the largest such procurement ever in the U.S.

Equinor and its partner, BP, will develop two separate projects: an additional 1,260 MW for the companies’ Empire Wind in the New York Bight, and the 1,230-MW Beacon Wind, to be located more than 60 miles east of Montauk. State officials had already selected the initial 816-MW phase for Empire Wind, and Beacon Wind could add up to 1,170 MW in the future.

“These projects will deliver homegrown, renewable electricity to New York and play a major role in the state’s ambitions of becoming a global offshore wind hub,” Equinor CEO Anders Opedal said in a statement.

The new contracts bring the state’s total OSW procurement to about 4.4 GW, nearly half the 9 GW targeted by 2035. Along with Empire Wind 1, New York in 2018 selected the 816-MW Sunrise Wind project and the 130-MW South Fork Wind Farm.

Equinor
Empire Wind is located 15 to 30 miles southeast of Long Island and spans 80,000 acres, with water depths between 65 and 131 feet. The lease was acquired in 2017 and is being developed in two phases (Empire Wind 1 and 2) with a total installed capacity of more than 2 GW (816 and 1,260 MW). | BOEM

The terms for the latest deals have not been announced, but officials estimate the projects will bring $8.9 billion in investment and create more than 5,200 jobs, an economic stimulus sweetened by commitments from companies to manufacture wind turbine components in New York. For example, the country’s first OSW tower-manufacturing plant will be built at the Port of Albany; a turbine-staging facility and operations and maintenance hub will be set up at the South Brooklyn Marine Terminal; and other support activities will take place at the ports of Coeymans, Jefferson and Montauk Harbor in Long Island.

Other Projects

New York also made several other announcements related to renewable and clean energy as part of the third segment of Gov. Andrew Cuomo’s State of the State address, which began Monday. (See Cuomo Outlines Green Path for New York in 2021.)

The state issued a solicitation for transmission projects to bring renewable energy from upstate and Canada to New York City as part of Tier 4 of its Clean Energy Standard. The state is hoping these transmission “arteries” will feed a 250-mile, $2 billion green “superhighway” project

“Supercharging the new transmission superhighway will be vital to completing New York’s nation-leading green economic recovery and accelerating renewable energy development programs,” it said.

Equinor
New York Gov. Andrew Cuomo delivers the energy portion of his State of the State address on Jan. 13. | New York DPS

Transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected without coordinated planning, OSW Growth to Test New York’s Transmission Grid.)

In addition, the state announced it will this year contract for 23 solar farms and one hydroelectric facility worth more than 2,200 MW.

It is also investing $20 million in a new OSW Training Institute based at the State University of New York at Stony Brook and Farmingdale State College to train at least 2,500 people for jobs in renewable energy. New York State Energy Research and Development Authority and SUNY issued the first solicitation for advanced technology training partners to train the first group of workers beginning this summer.

Anne Reynolds, executive director of the Alliance for Clean Energy New York, lauded the news but said, “There is some unfinished business in helping renewables get built, and that is providing some guidance to towns on how to properly value and tax wind and solar projects. ACE NY is calling on the governor and legislature to devise a pathway to standardized taxation for renewable energy.”

“The governor’s focus on transmission upgrades will ensure that the clean power generated by offshore wind projects is brought to the grid in an efficient and cost-effective manner,” Joseph Martens, director of the New York Offshore Wind Alliance, said in a statement.