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November 1, 2024

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More Federal Outreach Needed to Support Clean Energy Development on Tribal Land

LAS VEGAS — The government and developers need innovative capital approaches and a commitment to building deep relationships to unlock the potential of clean energy development on tribal lands, experts said in a panel at this week’s RE+ conference held at the Venetian Expo and Caesars Forum.

However, the federal government is behind on outreach to tribal leaders about how to address financing and skill gaps, RTO Insider was told.

Tribal land accounts for 5.8% of the U.S. landmass but 6.5% of utility scale renewable energy generation potential, said Margaret Tallmadge, senior development manager at Navajo Power, a majority native-owned utility scale solar developer working with tribal nations and communities across the U.S.

Barriers to developing this “outsized potential” include “access to capital; limited opportunities to build technical capacity and internal capacity within tribes to pursue their own projects; and minimal knowledge of tribal sovereignty, federal Indian law and regulatory complexities in Indian country,” Tallmadge said.

Some of those barriers are exacerbated by the federal government, which is lagging in its trust responsibility to tribes, Paul Dearhouse, a senior consultant to the Tribal Energy Loan Guarantee Program at the U.S. Department of Energy’s Loan Programs Office (LPO), told RTO Insider. “We’re a few years behind in actually sending out a ‘Dear Tribal Leader’ letter, saying, ‘Here’s a program designed to finance tribal energy projects. What’s your thoughts? What’s your feedback? What are the best ways to do that?’ We haven’t done that to date.”

Tribal input is vital to develop appropriate ways of dealing with the unique challenges tribes may face, where they have land ideal for renewables development but little access to capital and often no experience working with developers whose incentives and financing structures are designed with short-term ownership rather than long-term land stewardship in mind.

Developers working with tribes also need to be innovative, balancing the need to craft project structures that enable the tribe to participate without a large capital outlay with financiers’ desire to have traditional PPAs, said Kevin Blaser, managing director of energy systems at Bakinaw Federal Contracting.

One example of where limited access to capital creates issues is with interconnection queues. While a pain point for most utility-scale development, they create an even larger challenge for projects on tribal lands, Dearhouse said. FERC orders and rules implemented at the RTO level to fix aging infrastructure can result in escalating fees to maintain a project’s position in the interconnection queue. Most tribes won’t have the large amount of capital needed to maintain their queue position, creating “a huge barrier,” but also an opportunity.

“This is a new frontier to make our LPO offerings better, to do a proper rulemaking for our program and to really listen to tribes that are in the queues across the nation, to ask: ‘Are there better ways that the Loan Programs Office could design the program to help address that specific gap?’” he said.

Developers Must Invest in Relationships

While funding mechanisms are important, developers seeking to build clean energy resources on tribal lands must start with building a relationship, Blaser said. “If you’re going to work or partner with tribes — and there’s a ton of benefits to doing that — you really have to take the time to learn their culture, learn what they’re trying to do, and understand what their strategy is, even if their strategy is ‘we don’t know.’”

There is no single right way of working with tribes, Blaser said: “Because there are 576 or so federally recognized tribes, there are 576 different ways of doing it. There are all those bodies of laws; every culture is different.”

A long-term perspective and partner mentality is essential as developers work with tribes, said Dave Harper, head of tribal engagement at the Alliance for Tribal Clean Energy. “You don’t want to be an outsider; you want to come in as a partner mentality. What does being a partner mean? It means that we’re going to be fair with each other, we’re going to be respectful. We’re going to be able to have dialogue and to sit down.”

Tribes need to use those partnerships when they have limited internal knowledge or bandwidth, Dearhouse said. “For utility-scale projects, many times a tribe has a part-time environmental coordinator, so they really have to bring in trusted partners like the fellow panelists here that can really help fill in that piece.”

A relationship with the LPO also is important for tribes seeking to deploy renewable projects on their lands. “We are long-term patient capital. The path that we walk to get a tribal applicant in the door through to funding can be long, months to even a couple of years, because of the steps that we take, but for a really responsive applicant, it can be expedited two months, but not every tribe’s ready.”

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MISO: Expect More Expensive Annual Transmission Packages

MINNEAPOLIS — MISO’s lead planners on Tuesday told their Board of Directors that more expensive annual Transmission Expansion Plans (MTEPs) will become the norm, saying MTEP 23’s $9.4 billion package is a sign of future scattershot load growth in the footprint.

MTEP 23 contains 578 projects at $9.4 billion, more than doubling MTEP 22’s investment. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

Senior Director of Transmission Planning Laura Rauch acknowledged that MTEP 23 is the largest MTEP cycle in MISO’s history that doesn’t include long-range transmission plan (LRTP) projects or Multi-Value Projects.

During a meeting of the MISO Board of Directors’ System Planning Committee on Sept. 12, Rauch said most MTEP 23 projects are needed for reliability amid “localized load growth rather than bulk increases to load.” She characterized the bump in load as “spot load growth.”

MISO Director Nancy Lange asked whether the RTO anticipates “these lumpy, large investments” in MTEP cycles into the future.

Rauch said MISO members have indicated large industrial and commercial load additions will persist. She said MISO planners are expecting more economic growth in the footprint and sizable demand from new data centers and green hydrogen facilities.

MISO Director Barbara Krumsiek asked if funds from the Inflation Reduction Act are behind the jump in transmission needs.

“It’s such a substantial leap. Has it been long in the making or recent?” she asked.

Rauch said the upswing in spending appears to be occurring independent of government funding.

MISO Director Mark Johnson said despite the billion-dollar costs of two MTEP 23 projects, the projects differ from LRTP projects because they’re meant to be in service within three years, not the approximate decade allotted for the long-term planning.

Rauch said MISO remains “firmly committed” to recommending LRTP projects in MISO South despite the large amount of MTEP 23 investment in the region. She said the MTEP 23 projects don’t “preclude” separate, future solutions for long-term transmission needs in the South.

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MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation

MINNEAPOLIS — MISO’s quarterly Board Week explored the reasons behind MISO’s growing number of generation projects that have the stamp of approval to connect to the system but remain unbuilt.

49 GW Greenlit but Unfinished

MISO said many of its new resources that have struck generator interconnection agreements are beset by delays and cancellations, “mostly driven by build-related issues.” It said those lost and paused resources increase risk for a “future capacity or reliability attributes shortfall.”

By MISO’s count, 49 GW approved through its interconnection queue are awaiting construction, with an average delay to commercial operations of more than 650 days.

Scott Wright, MISO | © RTO Insider LLC

“That’s nearly 50 GW. This is pretty sizable. … This is a very pressing situation. We need to get iron in the ground. That’s what needs to happen,” Executive Director of Resource Planning Scott Wright said during a Sept. 12 System Planning Committee meeting of the Board of Directors. He added that MISO is negotiating new GIAs all the time and the postponed gigawatt amount is certain to rise by year’s end.

Wright said MISO’s plan to place an annual megawatt limit on project proposals, collect higher entry fees, enact escalating penalty charges and require developers to prove they have secured land will make for more certain generation projects that ultimately will mitigate long-term risk. (See MISO Sticks with MW Caps, Higher Fees to Pare Down Queue Requests.)

“With all the capital flowing in, it’s not hard to imagine a queue that’s 500 GW,” Wright said. He added MISO needs to be more selective about the projects it allows in to produce good network upgrade studies and approve projects that are a sure thing.

But Wright said incoming, mostly renewable generation likely won’t fare well in terms of accredited capacity. He also said EPA’s proposed carbon rule stands to pull the plug on “tens and tens” of gigawatts.

MISO has said EPA’s proposed emissions rule for fossil plants would supercharge retirements so they outpace the commercialization of new technologies like green hydrogen and carbon capture. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

“Thank you so much for that very calming discussion,” MISO Director Mark Johnson joked.

MISO members at a Sept. 13 meeting of MISO’s Advisory Committee were light on answers as to how to get the 49 GW online sooner.

“These are not speculative projects. We ran into the pandemic and supply chain issues,” Invenergy’s Arash Ghodsian said.

Wisconsin Public Service Commissioner Tyler Huebner seconded that view. He said developers ran headlong into the pandemic, and then a federal investigation into solar panels hampered new capacity.

“It has been a compounding of issues on the solar side in particular,” Huebner said.

“It’s incredibly challenging to build out new infrastructure, new power plants,” Invenergy’s Eric Thoms added.

North Dakota Public Service Commissioner Julie Fedorchak suggested MISO and members simply allow more time to develop generation. She said special interest groups and landowners are getting more vocal in proceedings at state commissions and commissioners are having to extend timelines to hear them out.

“I think we need to just bake in more time. Not to give up, but just be realistic,” she said.

Ameren’s Jeff Dodd seconded that longer timelines probably are the new reality. He said there’s more “fatigue” these days among landowners who are asked to host infrastructure.

Clean Grid Alliance’s Beth Soholt asked MISO for more data behind the delays on new build capacity, including locations and whether local communities are opposing projects. However, Soholt said transmission construction must catch up to meet the needs of generation developers.

“We have a transmission problem — we’re working on it — but we did have a 10-year lag between the multivalue projects and [the first long-range transmission portfolio]. So, we have a backlog in some of the generation projects that want to connect,” she said.

Solholt said it’s important the nearly $2 billion Joint Targeted Interconnection Queue (JTIQ) portfolio of 345-kV lines is built to ease the queue backlog. She also said MISO’s Environmental Sector prefers members not simply leave fossil generation operating on the system for “longer and longer.”

WEC Energy Group’s Chris Plante said though MISO can complete scores of generator interconnection agreements, some projects still are “conditional until the transmission reinforcements are there.”

“I want to make sure we have a heightened sense of urgency,” MISO CEO John Bear said a day later at the MISO board meeting. He said MISO is up against a wave of generation retirements and similarly tapering reserves at PJM and SPP, which means MISO won’t be able to rely on imported power from neighbors in the future.

“We’re going to have to take care of ourselves,” he said.

Bear said while MISO can export on windy days, it often runs into trouble when wind drops off. He advocated for “dispatchable, long-duration assets” on the system. He said though MISO remains fuel neutral, “we’re big fans of reliability.”

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NERC Seeks Comment on IBR Registration Proposals

NERC is seeking comment from industry stakeholders on proposed changes to the organization’s Rules of Procedure (ROP) intended to meet FERC’s order from last year to identify and register the owners of grid-connected inverter-based resources (IBRs).

The ERO posted the proposal for a 45-day comment period Wednesday, citing the commission’s November order directing NERC to describe its plans for registering IBRs (RD22-4). (See FERC Addresses IBRs in Multiple Orders.) NERC submitted its registration strategy in February, and FERC approved the work plan in May. (See FERC Approves NERC’s IBR Work Plan.)

FERC’s order was motivated by concerns over the ongoing transition from conventional generation resources to IBRs like wind and solar facilities. Currently, the ERO’s rules defining which resources must register with NERC, follow its reliability standards and respond to its alerts do not apply to many smaller IBRs. Updating the ROP is the first step in NERC’s work plan. The next stages are identifying candidates for registration, to be done by May 2025, and carrying out the registration process, to be finished by May 2026.

The changes before industry will apply to Appendices 2 (Definitions), 5A (Organization registration and certification) and 5B (Compliance registry criteria) of the ROP.

In Appendix 2, NERC proposes to add two new definitions — generator owner-IBR (GO-IBR) and generator operator-IBR (GOP-IBR) — to the registry criteria, while also updating the definition of “reserve sharing group” (RSG) to be consistent with that proposed by Project 2022-01 (Reporting ACE definition and associated terms).

The addition of GOP-IBR represents a change from the work plan NERC submitted in March, which included only GO-IBR. NERC staff said at the time that it felt GO-IBR could be used in reference to both owners and operators of IBRs, but at FERC’s prodding, it pledged to consider using additional terms.

Proposed changes to Appendix 5A include adding the GO-IBR, GOP-IBR and distribution provider-underfrequency load shedding (DP-UFLS or UFLS-DP) functions to the registration functions list. The DP-UFLS term indicates entities that own, control or operate UFLS-protection systems needed to implement grid protection programs but do not meet any of the other criteria for registering as distribution providers. NERC also proposes to clarify the Compliance Committee’s process for reviewing registration appeals.

The revisions to Appendix 5B would specify that entities registered as GO-IBRs or GOP-IBRs must own and maintain, or operate, inverter-based generation resources with an aggregate nameplate capacity of at least 20 MVA, which deliver their capacity to a common point of connection at a voltage at least 60 kV. Additional revisions will further clarify which entities should be considered candidates for registration, remove dated information and add the RSG function to ensure consistency with Appendix 2 and Project 2022-01.

The ERO will accept comments on the proposed changes through Oct. 30. After the comment period is over, NERC plans to submit the changes for approval at the Board of Trustees’ next meeting in December and then to FERC for final approval.

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Efficiency and Reliability are Debated at House Energy Hearing

The partisan divide on energy efficiency and other policies was on display at a hearing Wednesday of the House Energy and Commerce’s Energy, Climate and Grid Subcommittee.

The panel examined a series of bills from Republicans, including the Guaranteeing Reliable Infrastructure Development (GRID) Act from Subcommittee Chair Jeff Duncan (R-S.C.), which would require any federal agency implementing a rule that affects reliability to bring it before FERC. Other legislation would delay a DOE proposal to implement new efficiency standards for distribution transformers for five years and limit the department’s ability to issue new efficiency standards across the board.

Duncan cited the recent NERC report that listed energy policy as threatening reliability as a reason to support his bill requiring more oversight by FERC. (See ERO Adds Energy Policy to Risk Priorities List.)

“There’s a looming resource adequacy crisis. We all need to take this morning seriously and do more to ensure reliability and affordability of the energy system,” Duncan said. “FERC has allowed the distortion of market incentives such as state and federal subsidies aimed at promoting the deployment of renewables to interfere with electricity price formation. This has contributed to the early retirement of reliable generation assets like nuclear and natural gas.”

EPA’s proposed power plant rule would add to the problem as it would limit the amount of time fossil plants can operate, he added.

The GRID Act is a broad proposal that would cover many potential government actions, making it hard to determine just how much work it would give to FERC, said David Ortiz, director of the commission’s Office of Electric Reliability.

“As a general matter, FERC and the ERO, NERC, have the necessary expertise to understand and comment on the potential effect of proposed regulatory actions on the reliability of the bulk power system,” Ortiz said. “However, fulfilling the goal of the GRID Act would require detailed, interconnection-wide modeling and analysis beyond FERC’s capability.”

FERC might not have access to the data needed to perform the studies required under the proposed bill, he added. Other organizations could do the analysis, with Ortiz pointing to DOE’s national laboratories.

Ranking Member Diana DeGette (D-Colo.) said everyone in the room agreed reliability is important and will be even more so in a warming world where summer power outages threaten lives.

“It’s clear, a reliable source of electricity is paramount to our nation’s health and well-being,” DeGette said. “I think that one of the ways to ensure we have reliable electricity is through energy efficiency.”

Increasing energy efficiency helps to stretch out the current energy supply to serve more consumers reliably, while also saving them money.

The Biden Administration has been implementing efficiency standards at DOE that would save up to $570 billion after DOE under President Trump missed dozens of deadlines under the law to either issue a standard or explain why none was needed. DeGette argued the bills before the committee do not deal with reliability.

“Instead, what I see is bills that in the name of reliability, would gut energy efficiency standards that are saving Americans money, and that are cutting down on our energy use,” she added.

Mid-Carolina Electric Cooperative CEO Bob Pauling in testimony came out against a proposed DOE standard that would require the industry to stop using standard “grain oriented electric steel” distribution transformers at a time when supply chains for the vital infrastructure already are stressed.

“The utility industry needs manufacturers to be 100% focused on increasing output, not adapting to new, government mandated efficiency requirements that are not technologically feasible nor economically justified,” he said in written testimony.

DOE Assistant Secretary for Electricity Gene Rodrigues noted that the transformer standard still is just a proposal, which the agency was required to take up under a consent decree, and said the department takes the issue of electric reliability and the need for more transformers seriously.

“That is why DOE expressly asked stakeholders for comment on timelines required for compliance with the proposed standard, as well as comments on the availability of key components,” Rodrigues said.

The efficiency standard is just part of DOE’s work on transformers. It also is working with the rest of the government and other stakeholders to help bolster the domestic supply chain for key grid components for decades to come, he added.

“We have provided national projections of the long-term demand growth for distribution transformers to provide America’s manufacturers with investment certainty that will help them to expand capacity,” Rodrigues said. “We have connected manufacturers with suppliers of difficult-to-source grid components. We have utilized legislation passed by this Congress to provide funds for distribution transformers, such as the $10 million in transformer rebates and $10 billion in 48C tax credits.”

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NYPSC Continues Legal Battle Over NYISO’s 17-year Amortization

The New York Public Service Commission on Tuesday petitioned a federal court again to reconsider FERC’s approval of NYISO’s proposed change to the timeline for demand curves in its installed capacity market auctions (ER21-502).

This is the third time the PSC has asked the D.C. Circuit Court of Appeals to rule on NYISO’s proposal to implement a 17-year amortization period when calculating the net annual cost of a hypothetical peaking power plant in its capacity markets and comes after FERC declined the PSC’s request for a rehearing on Monday. (See NYPSC Seeks FERC Rehearing on NYISO’s 17-Year Amortization.)

NYISO is mandated to update the assumed operational lifetime of a hypothetical fossil fuel plant in its capacity market auctions every four years, but, in response to aggressive state climate and energy legislation, the ISO proposed reducing that assumed lifetime from 20 to 17 years.

The ISO argued the 2019 Climate Leadership and Community Protection Act imposes such strict net-zero standards for fossil fuel plants that their operational use would be dramatically reduced; however, the PSC contended the adjustment to a shorter period hurts New York ratepayers and is speculative.

The PSC reiterated previous arguments when requesting the court review FERC’s decisions and its denial for a rehearing, including that a 17-year period could cost consumers $400 million, claiming FERC should have waited to rule until addressing other pending rehearing requests related to NYISO’s compliance and asserting that FERC’s decision departs from precedent.

The petition also cites a dissent submitted by Commissioner Mark Christie, who expressed concerns about the May approval of the 17-year timeframe, which reversed previous rejections by FERC. Christie opted to not elaborate, citing pending rehearing requests related to that approval order.

Despite the legal wrangling, NYISO already has implemented the 17-year amortization period as part of its demand curve reset.

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UN Report Calls for Quicker Global Emissions Reductions

While the Paris Agreement has led to some climate progress, the world is not on track to meet its goals, and deeper cuts to emissions need to start happening soon as midcentury approaches, the U.N. said in a report released last week.

The report — the first “global stocktake” by the U.N., released Sept. 8 — is meant to assess the global response to climate change and inform the discussions at the next Climate Change Conference, to be held beginning Nov. 30 in the United Arab Emirates.

“I urge governments to carefully study the findings of the report and ultimately understand what it means for them and the ambitious action they must take next,” U.N. Executive Secretary of Climate Change Simon Stiell said. “It’s the same for businesses, communities and other key stakeholders. While the catalytic role of the Paris Agreement and the multilateral process will remain vital in the coming years, the global stocktake is a critical moment for greater ambition and accelerating action.”

When the Paris Agreement was adopted in 2015 — with the goal of limiting the increase in the global average temperature to 1.5 degrees Celsius by 2050 — the forecasts suggested the temperature would rise by 3.2 C by the end of the century, World Resources Institute’s Jamal Srouji said on a web conference Wednesday. Forecasts dropped last year to 2.4 to 2.6 C, with the possibility of reaching 1.7 to 2.1 if countries’ net-zero-emissions targets are fully implemented.

“While progress has been made, the report makes clear that the world is not on track to meet the goals of the Paris Agreement and that much more action is needed now on all fronts,” Srouji said.

The report underscores that “system transformations” are needed to hit the midcentury goals, which would avoid some of the worst consequences of climate change but still require some adaptation measures. The last decade saw temperatures average 1.1 degrees Celsius higher than the pre-Industrial Revolution average, while concentrations of CO2 hit 410 parts per million in 2019 — a level higher than in the previous 2 million years.

Global emissions need to peak before 2050 to stay on track to keep warming at 1.5 C or lower. While the report said that needs to happen as soon as possible, peaking will take longer in developing countries than it will in the developed world.

In the energy industry, system transformation involves eliminating the use of unabated fossil fuels and scaling up renewable energy and other clean sources, the report said. Phasing out unabated fossil fuels will be a hotly contested topic at climate negotiations going forward, said Rachel Jetel, co-director of WRI’s Systems Change Lab.

“But without tackling the primary source of the problem — burning and, importantly, financing fossil fuels — we will not be able to solve the climate crisis,” she added.

Energy system mitigation measures could account for 74% of total global mitigation in reaching net-zero emissions, the report said.

Even the head of the International Energy Agency recently said new large-scale fossil fuel projects now carry not only climate risks, but also financial risks, Jetel said. Economics and the urgency around climate change are coming together, she said.

“In addition to transitioning away from fossil fuels, annual renewable energy capacity additions should more than triple by 2030,” Jetel added.

Renewable energy trends have been promising recently, with the unit costs for solar and batteries both falling by 85% from 2010 to 2019, while the cost of wind was down 65% over the same period. That has led to a significant increase in solar deployment, with growth rates of more than 10 times, and electric vehicles by 100 times.

Strengthening power grids and storage is critical to unlocking the potential of renewable energy sources and to providing clean power as transport, industry and buildings electrify, the report said.

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ISO-NE Recommends Delaying FCA 19

ISO-NE is recommending a one-year delay of Forward Capacity Auction 19 (FCA 19) to implement resource capacity accreditation (RCA) changes and determine whether to move to a prompt and seasonal capacity market, the RTO told the NEPOOL Markets Committee on Tuesday.

Since June, the RTO has been taking stakeholder feedback on the best path forward for FCA 19 following a delay caused by a software issue in the RCA process, as well as on a potential move to a prompt and/or seasonal market. (See NEPOOL Debates Options for FCA 19.) FCA 19, scheduled for February 2025, corresponds with Capacity Commitment Period 19 (CCP 19), which runs from 2028 to 2029.

After laying out a series of options in previous meetings, ISO-NE endorsed “option 2A,” which would provide some extra time to finish the RCA process for FCA 19 and further discuss the merits of capacity market changes.

Chris Geissler of ISO-NE said this option “recognizes the importance of simultaneously implementing a revised capacity accreditation framework that coincides with the elimination of the minimum offer price rule (MOPR) for FCA 19.”

The RCA project is intended help the organization “more accurately reflect resource contributions to resource adequacy.” ISO-NE has expressed its desire to time the implementation of these changes with the scheduled elimination of the MOPR. (See FERC Accepts ISO-NE’s MOPR Transition Plan.)

“While some stakeholders prefer maintaining the status quo (FCA 19 without RCA), the ISO is concerned it may not adequately prepare the region for the changing resource mix and expected clean energy system,” Geissler said.

Clean Energy Stakeholders Weigh in

A range of clean energy stakeholders outlined questions, comments and concerns about the potential capacity market changes. The comments highlight the lack of consensus among various renewable energy groups, along with uncertainty about how a prompt seasonal market would affect resources.

Deepwater Wind Block Island, a subsidiary of Ørsted, supported implementing RCA changes and moving to a prompt and seasonal capacity market for CCP 19, writing that the move would limit uncertainty for long-term investments while helping reliability. The company added that ISO-NE’s preliminary analysis of the RCA design indicated it would enable offshore wind resources to clear more capacity.

“The combination of incorporating RCA and the removal of the MOPR in CCP 19 will enable offshore wind resources the opportunity to compete with other existing resources on a more even playing field,” wrote Eric Wilkinson of Ørsted. “Ratepayers will benefit from these changes by increasing the amount of capacity being provided from clean energy resources.”

In contrast, representatives of New Leaf Energy and SYSO Inc. expressed their opposition to delaying the auction and supported holding it under the current rules without RCA changes. The companies argued that any delay of the auction would introduce uncertainty and hurt new resources looking to connect to the grid, because new generators rely on the forward capacity market to secure capacity rights.

“Postponing the FCA without a replacement process for generators to secure these rights will prevent new resources from knowing whether they can access the capacity market, threatening the financial viability of these projects, as well as the pace of the clean energy transition,” the memo said.

The companies added that delaying the auction could lead to a backlog of projects in the interconnection queue once a new process is implemented.

ISO-NE told the Markets Committee it might need to separate the interconnection process from the capacity market to comply with FERC Order 2023 no matter which capacity market design ultimately is chosen (RM22-14). (See FERC Updates Interconnection Queue Process with Order 2023.)

“To address FERC Order 2023, the ISO will be required to migrate to a single annual cluster process, with equal queue positions and shared upgrade cost allocation within the cluster, for studying new interconnections,” ISO-NE noted.

In an August letter to ISO-NE, Advanced Energy United, which advocates for clean energy policies on behalf of its member companies, wrote that there are significant “information gaps” surrounding the effects of ISO-NE’s stated options for CCP 19 on new resources, retirements, the RCA process and subsequent capacity commitment periods.

“We do not feel stakeholders can make informed decisions without further explanation addressing these information gaps,” Advanced Energy United wrote. “While we appreciate the time constraints driving ISO to move quickly to land on a preferred path forward, we believe the significance of the decision necessitates a fulsome exploration of the implications of each pathway, and we are not yet satisfied that ISO-NE and NEPOOL have completed such an exploration.”

Aleks Mitreski of Brookfield Renewables expressed concerns in a presentation to the Markets Committee on Tuesday relating to the entry and exit of resources, along with transmission upgrades. Mitreski added that some of the issues with the forward capacity market likely could be fixed without overhauling the entire market design.

Next Steps

ISO-NE proposed making an initial FERC filing by the end of this year to delay the auction, followed by another filing next year to either finalize the one-year delay including the RCA changes or to create a new schedule to implement a prompt auction for FCA-19, which would be held in 2028.

ISO-NE will present the detailed tariff revisions at the October MC meeting, followed by a November MC vote and a Participants Committee vote in December.

Also at the October MC meeting, ISO-NE will resume discussion on the RCA proposal, which likely will extend into next year. The RTO is targeting an August 2024 vote on the proposal.

ISO-NE also has commissioned the Analysis Group to conduct a qualitative and quantitative analysis of the potential effects of moving to a prompt and/or seasonal market. The consulting firm will need to work on a tight schedule, as ISO-NE expects it to present to the MC the scope of its work in October, the methodology in November and results in December.

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NW Stakeholders Divided on BPA Timeline for Day-ahead Decision

Northwest electricity sector stakeholders this week expressed divisions over the Bonneville Power Administration’s plan to pursue an aggressive timeline for deciding whether to join CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+.

BPA’s decision will carry significant weight in the Northwest, where the federal power marketing agency controls more than 22 GW of mostly hydroelectric generation, operates 70% of the transmission grid and serves dozens of large customers, including the region’s extensive network of publicly owned utilities.

Its choice also could influence the decisions of system operators elsewhere in the West. Supporters of the accelerated timeline seem to be hoping for such an outcome, not only to boost the clout of BPA but of the Northwest in general.

“We’ve been followers for far too long, and we actually have a chance here to be a leader — and, yes, that means sticking our neck out there a little bit,” Shawn Smith, managing director of energy resources at Chelan County (Wash.) Public Utility District, said Monday at a BPA public workshop to discuss the day-ahead market decision. Smith was referring to a view shared by many in the region that public power entities became involved in CAISO’s Western Energy Imbalance Market (WEIM) too late to hold much sway in its initial development.

“I think it’s really important for BPA to come out and express where they’re leaning [in] Q1 of next year,” said Laura Trolese, director of Western markets strategy at The Energy Authority, which provides energy market services to public power entities.

Trolese noted the region is facing a wave of changes related to resource adequacy, state climate policies and organized electricity markets.

“It’s moving at a pace that we’ve never seen, but we have to start making decisions and move forward with all of the uncertainty and figure things out as we go. We just can’t wait for everything to be figured out before BPA makes a decision,” she said. “At that point, there’s no decision to make, so I really appreciate these guys stepping up and starting this process.”

Michael Linn, director of market analytics at the Public Power Council, acknowledged that SPP has not yet completed a Markets+ tariff and many issues related to the initiative remain outstanding. (The RTO expects to file with FERC in early 2024.)

“But we know about governance; we know about some price formation. And, frankly, the way Bonneville signals or leans may ultimately kind of determine a path forward for either of these markets,” Linn said. “So I think it’s important to acknowledge that … indecision at this point is a decision and it almost is a forfeiture of our leverage as a region [that has] a lot of transmission and hydropower.”

‘Crucially Important’

Other meeting participants questioned the need for such speed.

Speaking on behalf of the Western Public Agencies Group, which represents Oregon and Washington public utilities involved in BPA proceedings, Lea Fisher contended that BPA’s process for joining the WEIM and the Western Power Pool’s Western Resource Adequacy Program (WRAP) seemed more “substantive” than the process envisioned for choosing a day-ahead market. Fisher pointed out that BPA has proposed a seven-month process consisting of five workshops, compared with a 14-month process with 10 workshops for the WRAP and a five-phase, three-year process for joining the WEIM.

“You can see how the process BPA has currently outlined for the decision to join a day-ahead market seems light in comparison,” she said, asking whether there would be another “follow-on” process after the agency made its determination.

Matt Hayes, BPA program manager and policy analyst, said the seventh-month process would be “analogous” to the agency’s initial process for deciding to join the WEIM, which would be followed by a “much longer” process related to implementation.

But chief among the skeptics of BPA’s timeline was Fred Heutte, senior policy associate with the Northwest Energy Coalition (NWEC), who said the “big question” was the uncertainty around FERC’s responses to the EDAM and Markets+ tariff filings. Heutte said the EDAM filing was “very complete,” but took five years to put together, while “much, much less time” has been spent on developing Markets+.

“And it’s really evident sitting in some — not all — of the Markets+ meetings, that there are a lot of key pieces that haven’t yet been hammered down,” he said, adding that NWEC is “feeling a bit of unease about the schedule.”

“I think you’re just articulating the challenge and sort of the misery of what my group deals with on a daily basis,” Russ Mantifel, BPA director of market initiatives, said. “But other entities are making decisions, right? But Bonneville is not in a vacuum, where we get to have self-determination over exactly what all of our options are going to be. And I’ve never delivered what has been considered to be good news. I’ve never run a process where people thought we had enough time.”

Heutte said BPA faces a “crucially important” choice.

“Among other things, it’s a choice to leave the EIM after taking so long to get into it and realize some real value from it. And the big thought that I have right now is, look before we leap,” he said.

‘Not Equally Distributed’

If NWEC’s reservations about the timeline are colored by a concern that BPA could stymie the potential for a single West-wide electricity market by choosing Markets+ over EDAM, then BPA officials did little to assuage that concern on Monday.

Industry sources not authorized to speak on behalf of their organizations have told RTO Insider that BPA is favoring Markets+ — in part because of an in-depth economic study commissioned by the Western Markets Exploratory Group  to ascertain Western market benefits.

The sources said the study, which has not been released to the public, shows that, in a single market, a disproportionate share of the benefits would flow to California, while a two-market solution would provide greater financial benefits to BPA and the Northwest at large.

Mantifel spoke around the specifics of the study on Monday but appeared to confirm that assessment.

“The results are complicated … and identifying who receives which benefits is also an important part. Societally, a broad footprint produces more diversity, more optimization [and] produces more benefits, but I think they’re not equally distributed,” he said.

BPA plans to hold a call on Oct. 23 to discuss the “quantitative results” of the study related to the agency, he said.

During the meeting, Mantifel also praised BPA’s experience in working with SPP during the Markets+ design process.

Responding to a question about whether BPA preferred SPP’s stakeholder-driven process for dealing with market initiatives over CAISO’s staff-led approach, he said, “I think we’ve really enjoyed our experience with the SPP process. Being engaged in it is difficult; sometimes it feels messy. But that process, I think, is a good representation of how representative that organization is.”

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SPP REAL Team Compromises on PBA, ELCC Revisions

DFW AIRPORT, Texas — SPP stakeholders last week asked two working groups to consider compromise language on a pair of tariff revisions related to resource adequacy policies.

The Resource and Energy Adequacy Leadership (REAL) Team voted to ask the Supply Adequacy and Cost Allocation working groups (SAWG and CAWG) to review the revision requests (RR554 and RR568) following the team’s Sept. 8 meeting. RR554 details the performance-based accreditation (PBA) policy, and RR568 lays out the effective load-carrying capability (ELCC) policy.

SPP staff proposed the compromise after pushback from the Market Monitoring Unit (MMU) and a lengthy discussion among the REAL Team’s members. The Monitor said it couldn’t support RR554 as written over accuracy and equity concerns, and it said RR568 included inconsistencies that could be considered unduly discriminatory.

“I think it’s important that we attempt to restore trust among the MMU that we will deliver on commitments,” Texas Public Utility Commissioner Will McAdams, the REAL Team’s chair, said during the meeting. “I think this policy debate has highlighted that it’s just trying to identify and assign the appropriate vehicle to carry out these strategic aims of the organization.”

Texas regulator and REAL Team Chair Will McAdams listens to speakers during SPP’s Resource Adequacy Summit. | © RTO Insider LLC

Keith Collins, the MMU’s vice president, said he appreciated McAdams’ effort to advance the RRs.

“We’re supportive of considering [the potential RR changes] and moving them forward,” he said.

Staff said the compromise’s modifications could be implemented while still maintaining the RRs’ structural frameworks and timeline. The primary change is using seven years of historical outage data, rather than 10, in determining conventional resources’ accredited capacity under RR554.

The MMU had suggested five years of historical data, saying the PBA “asymmetrically” treats historical performance. It said outage exemptions are inconsistent with ELCC and performance is assessed over the entire season, not when needed.

The compromise also proposes adding out-of-management-control events, such as tornadoes and other violent storms, in calculating the ELCC for wind, solar and storage resources, and weighting the PBA during resource advisories, conservative operations and energy emergency alerts.

Under RR554, PBA places more value on conventional resources that are reliable and available to perform when needed the most. It is intended to ensure the appropriate capacity value to calculate SPP’s planning reserve margin.

RR568 is a response to FERC’s rejection this year of SPP’s first attempt to add ELCC (the amount of incremental load a resource can dependably and reliably serve during peak hours). The revision reduces a three-tiered structure to just two, firm and nonfirm transmission service. Staff will study only firm service in its ELCC analysis. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

The Advanced Power Alliance’s Steve Gaw (left) makes his case during the REAL Team’s Sept. 8 meeting. | © RTO Insider LLC

The REAL Team has targeted the October series of governance meetings to gain approval of the two RRs. They are scheduled to be deployed for the 2026 summer season.

The SAWG meets Sept. 26-27 and the CAWG meets Oct. 3. The REAL Team will review their input during an Oct. 5 virtual meeting.

“Time is of the essence, and we need to have strategies in place that include contingencies,” Director Steve Wright said.