Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Endorsements (9:10-9:40)
1. Service on PJM for Rate and Waiver Filings under Governing Agreements (9:10-9:30)
Members will be asked to approve an issue charge addressing service to PJM of members’ tariff rate and waiver filings under the RTO’s governing agreements.
The change would require PJM be served when members and interconnection customers file with FERC rate tariff filings, service agreement filings or settlements under the agreements. PJM said the change is needed to ensure the RTO can intervene and participate in such proceedings to protect the interests of members and markets.
2. Operating Committee Charter (9:30-9:40)
Stakeholders will be asked to approve revisions to the Operating Committee charter.
The revised charter adds the phrase “reliability attributes and pertinent conditions” to paragraph 7, pertaining to the committee’s role in reviewing and recommending operating practices and procedures concerning system reliability.
Members Committee
Consent Agenda (1:40-1:45)
B. Endorse proposed revisions to update the process timing for generation deactivations in Part V and Attachment M of the tariff.
Members will be asked to endorse changes to the rules regarding the timing of its reliability reviews for generator deactivations.
PJM says the current deactivation rules are “inefficient and unsustainable” because each response is due 30 days after notification and the tariff does not provide additional time for multiple requests. Under the proposed changes, PJM would study retirements in four batches per year (beginning Jan. 1, April 1, July 1 and Oct. 1) and provide reliability notifications by the end of February, May, August and September.
Massachusetts is moving forward with a building energy code proposal that has been broadly challenged by legislators and environmental advocates who say the state is not going far enough to reduce fossil-fuel use in buildings.
The Department of Energy Resources filed draft regulations Friday with the Secretary of State for its update to Massachusetts’ building codes, which includes an update to base and stretch energy codes and a new, specialized opt-in code for net-zero building performance standards. The actions are required by the Next Generation Roadmap climate law passed in 2021.
A straw proposal on the matter released earlier this year was met with widespread criticism, largely because the proposed specialized opt-in code, which is supposed to be the most aggressive option that municipalities can adopt, does not allow cities or towns to mandate that all new construction be fossil-fuel free. (See Mass. Net-zero Building Code Proposal Faces Barrage of Criticism.)
The draft language for residential and commercial construction doubles down on that proposal.
In a summary of the proposal, DOER said that it recognized in drafting the specialized code that many building construction sites and high-rise structures do not currently lend themselves to achieving net-zero status. The specialized code, which municipalities can opt to adopt, allows fossil fuels in new buildings if they also include solar and are “designed with electric service and wiring sufficient for future electrification of space and water heating as well as any combustion equipment appliance loads,” DOER said in a summary of the proposal.
During the public comment period for the straw proposal, many local officials asked that the state allow municipalities to require fossil-free, all-electric buildings.
The stretch code is less ambitious than the specialized opt-in, but it still contains stronger requirements than the base building code. The proposed update to it, which would apply to the hundreds of towns in Massachusetts that have already decided to use the stretch code, increases the energy efficiency requirements for several types of new construction.
By 2024, it would require a Home Energy Rating System score of 45 for all-electric homes and a more stringent HERS 42 score for homes with any use of fossil fuels.
It also sets new standards for a Passive House pathway, adds ventilation requirements and requires that one parking space per home or a minimum of 20% of spaces in a new multi-family parking lot be wired for electric vehicle charging.
DOER will take public comments on the draft language through Aug. 12, with three public hearings scheduled in July and August.
The Conservation Law Foundation (CLF) is working to establish regulatory frameworks that incentivize infrastructure developers to analyze cumulative impacts of projects and protect environmental justice communities, said Caitlin Peale Sloan, vice president for Massachusetts.
An established EJ framework can “empower regulators to reject projects that overburden cumulatively impacted communities,” she said Wednesday during a climate and energy infrastructure panel hosted by the Northeast Energy and Commerce Association.
During the event, energy experts shared stakeholders’ and developers’ perspectives on the challenges of achieving climate targets and building infrastructure to meet those targets.
While CLF supports clean energy deployment, Sloan spoke from stakeholders’ perspective, saying that understanding cumulative project impacts “is critical to assess the impact of the proposed project on different stakeholders.” A cumulative analysis identifies impacts from a proposed project on the project area and the impacts of other actions from the past, present or future that also would affect the project area.
“In this current era, when developers and clean energy businesses really want to do the right thing by EJ populations, you have to use cumulative impacts analysis or you’re still going to wind up disproportionately burdening EJ populations in siting,” Sloan said.
EJ-focused regulations focus on cumulative burdens on EJ populations within the existing “well established framework of siting regs,” she said. CLF’s effort to raise the bar on cumulative impacts analysis seeks to ensure that developers are thinking about EJ communities in the early siting phase. Doing so, she said, could build community support for a project and avoid a “late wave of opposition.”
In Sloan’s view, EJ populations approach stakeholder engagement from a different perspective than under-burdened communities. If a project’s location, design and impacts are “totally locked in,” she said, it inhibits participation from community members.
They have “decades, centuries of well earned skepticism and concern about the intentions that major institutions have for an EJ community,” she said, adding that developers must engage with the community early in the design process, when change is still possible.
Massachusetts’ 2021 Next Generation Roadmap climate law directed the Department of Environmental Protection to issue regulations by the end of this year for incorporating cumulative analyses into the review of certain air permits. DEP will propose draft cumulative analysis regulations by October and take public comment on them through December.
At the beginning of this year, the Massachusetts Environmental Policy Act (MEPA) Office implemented new protocols for EJ community involvement in permitting processes and analysis of EJ community impacts, as directed by the climate law.
The new MEPA regulations represent “the first major changes” to the review process in “many years,” said TJ Roskelley, partner at Anderson & Kreiger.
Speaking during the event from the developers’ perspective, Roskelley called the new protocols “complicated.”
“There’s going to be a lot of learning by doing over the next year,” he said. “As soon as we start to get filings and some feedback from stakeholders and from the MEPA office, I think we will understand this process a lot better.”
The new regulation updates the existing thresholds for what constitutes a basic or extended project review in the permitting process. A review for a project within 1 mile of an EJ community (or 5 miles for projects that affect air quality) must move from a basic 30-day review to include a full environmental impact report (EIR).
Any project that meets the threshold for a full EIR also triggers an enhanced public engagement protocol, which requires notice of the project within a required time frame and “meaningful” outreach to promote public involvement.
Building Support
For Megan Aconfora, public involvement specialist at Burns & McDonnell, stakeholder engagement should change based on the community in which a project is located, but the process must be consistent across communities for developers to find broad success.
Engaging with an EJ community requires a developer to use “different tactics” from other communities, Aconfora said. In sensitive communities, a town hall conversation will not be “productive,” she said, adding that some communities need the developer to build trust.
“Sometimes trust means not immediately rolling in and talking about your project, but just showing yourself as someone that they can communicate with,” she said.
While early community engagement is critical for large-scale energy infrastructure projects, Joe Rossignoli, founder of the consulting firm Ross Emergent, said it’s possible to “design support into a proposal” by “making greater use of the existing transmission system.”
That approach might include, for example, using storage as a transmission asset to ensure bulk system reliability on lines that traditionally would be constrained to prevent outages.
“These devices allow lines that would otherwise be security constrained for N-1 contingencies to flow at their nominal capability,” he said. The instantaneous response, he added, prevents the line from experiencing a thermal overhold.
Another option is to take a fresh look at limits on the amount of power that can flow over a right of way. Doing so, Rossignoli said, would require a review of the Northeast Power Coordinating Council rules that permit the evaluation of extreme consistency violations based on the historic or projected variability in the use of lines on interregional corridors.
“What’s clear from recent developments is that cutting new rights of way to get customer access to power supply and in neighboring regions just isn’t doing the job,” Rossignoli said.
ARLINGTON, Va. — Attendees at the Infocast Transmission & Interconnection Summit last week greeted FERC’s June 16 proposal on interconnection as long overdue but expressed frustration that the commission had failed to address the issue of participant funding.
The commission unanimously approved a Notice of Proposed Rulemaking that would replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies (RM22-14). The commission also proposed more stringent financial commitments and readiness requirements for interconnection customers, which it said would discourage speculative interconnection requests. (See FERC Proposes Interconnection Process Overhaul.)
“Those are great fixes — going to help streamline everything,” said Brian C. Drumm, director of regional policy and RTO engagement for ITC Holdings. “But it’s also, I think, somewhat of a Band-Aid approach. … It’s not addressing the problem of this lack of transmission and this increasing cost that interconnecting generators are being asked to bear.”
Kevin McAuliffe, director of PJM and Northeast markets for nFront Consulting, said it is clear that grid planners can’t rely on the generator interconnection process to build out the system and that planners need to be more proactive in considering what is required to meet decarbonization goals. “As you get more and more generators in [the queue], it requires more and more big backbone upgrades to rebuild the system. And that’s hard for a generator to accommodate,” he said.
“One thing that is distinctly omitted from this NOPR is any way to address the deficiencies in the existing participant funding model,” said Tyler H. Norris, vice president of development for Cypress Creek Renewables. “We hope to see FERC address it in another venue.”
The NOPR said the existing serial study process may be unjust and unreasonable because an interconnection customer that triggers a network upgrade can be saddled with its entire cost even though it creates additional capacity for other interconnection customers that don’t share in the bill.
FERC proposed requiring transmission providers to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade.
But the 407-page NOPR includes just two brief mentions of participant funding, including a footnote to its observation that “although the crediting policy in the pro forma LGIP [large generator interconnection procedures] requires that the interconnection customer is ultimately reimbursed for the cost of the network upgrades, the large upfront network upgrade cost allocation may render a proposed generating facility economically non-viable, such that the interconnection customer is forced to withdraw from the interconnection queue.”
In a report to clients Monday, ClearView Energy partners said it expects FERC to issue an additional rulemaking addressing cost allocation beyond shared interconnection costs “as well as some of the mechanics of generator interconnection financing.”
Eliminating ‘Chicken’
Other aspects of the rulemaking also prompted comments during the three-day conference.
Arash Ghodsian, senior director of transmission and policy for EDF Renewables, acknowledged that he has a different perspective on the queue process than he did when he was a transmission planner for MISO.
“When developers used to come to us and say, ‘We need queue reform. We need efficiency,’ we used to push back and say, ‘Well, you know, it took us it took us a decade to get to where we are today.’ Now being on this side of the fence, I’m one of those who’s pushing [for] changes.”
Anton Ptak, director of transmission and interconnection for EDF, said planners should use the location of generators in the queue as a guide to the most attractive areas for siting. “If you can use that information in your planning process — to help guide where to put these large new lines or major rebuilds or reconductors — I think that will significantly help. It’ll take a little bit of … the game of chicken out of the interconnection process,” he said.
Several speakers praised FERC’s proposal to eliminate the “reasonable efforts” standard and penalize transmission providers $500/day for failing to meet study deadlines.
“I think that timelines for TOs are helpful if they have the resources to meet those timelines,” said Sarah Bresolin, director of government and regulatory affairs and wholesale markets policy for ENGIE North America. “That’s something that we struggled with at both the transmission and the distribution level. So some level of accountability there is helpful.”
FERC ‘Catching Up’
“I do feel like in some ways, FERC is catching up to what we just implemented in Duke territory [in North and South Carolina] with respect to the transition to cluster studies,” said Cypress Creek’s Norris.
Duke Energy (NYSE:DUK) implemented its first-ready-first-served, cluster-based process last year after it was approved by FERC in August (ER21-1579).
Kenneth Jennings, general manager of renewable integration and operations for Duke, said the company held stakeholder meetings for about nine months before it began drafting tariff changes.
“Once we did draft tariff changes, we shared those tariff changes with stakeholders and asked for feedback. Whenever we could incorporate recommendations from interconnection customers, we did it — as long as it didn’t compromise what we thought the integrity of the process was or reliability in any way.”
Jennings said interconnections become a problem “where there’s robust incentives for development.”
“When PJM started the RPM [Reliability Pricing Model] capacity market, there were immediate interconnection issues right away. … In North Carolina, the incentives were around solar; there was kind of this weird intersection between where the cost of solar declined and the avoided cost rates for [Public Utility Regulatory Policies Act] projects had reached the point where the cost was lower. And all of a sudden, we had a lot of activity. Initially, it wasn’t too bad because we had headroom in our system. … We ended up having this large influx of interconnection requests that we couldn’t get processed. And at some point, we were getting about four times the [number] of requests that we could process in a year.”
Southern Co. Reluctant to Abandon Serial Approach
Not everyone at the conference was ready to endorse FERC’s proposals, however.
Corey Sellers, transmission policy and services manager for Southern Co. (NYSE:SO), said his company supports the first-ready, first-service concept. “We were already looking at potentially some changes that would move us in that direction,” he said.
But he said the company is concerned about abandoning the serial process for cluster studies.
“We’ve been pretty efficient in being able to process serially our requests,” he said. “We were looking at something a little bit more of a hybrid. … Our biggest concern is the continual restudies that you see when you have a cluster process. Not sure exactly how that would work for us.”
The overwhelming support that members gave the proposed rule changes “was a PJM stakeholder success story,” said Erik Heinle, senior assistant people’s counsel for federal affairs and wholesale markets for D.C. “When PJM began this process back in late 2020, it was a very acrimonious process. … There was some serious disagreement about how we get there and, understandably, very frustrated generators who want to get on the system.”
Bhaskar Ray, vice president of interconnection and development engineering for Q CELLS USA, also praised PJM for “a very well engaged stakeholder reform process.”
But he said it’s unclear how PJM will handle the transition to the new rules. He also said his company also has concerns over how PJM would respond if Q CELLS’ lease options — acquired to demonstrate site control — expire before studies are completed.
Ray also said the company is seeing “a lot of cost overruns.
“This is an ongoing issue. I think one way to circumvent the problem would be to do more quarterly financial expenditure forecasts, because it’s very hard on developers to get these overruns of 50 [to] 60%.”
ARLINGTON, Va. — Frustration over the pace of transmission growth and lack of interregional planning mixed with optimism over FERC’s recent proposed rulemakings at Infocast’s Transmission and Interconnection Summit last week.
The sessions also featured debates over the role of grid-enhancing technologies (GETs) and the commission’s proposal to scale back Order 1000’s effort to subject transmission projects to competition. See related stories:
Last August, the Niskanen Center and the Clean Air Task Force released a report that called for adoption of the “5 P framework” to overcome opposition to clean energy infrastructure. The construct builds on the transmission concept of “planning, permitting and paying.”
“We propose adding ‘participation’ as a fourth ‘P’ and then ‘process’ as [the fifth]. Because one of the challenges of transmission [is that] every single project is unique, because every state in every region is different,” said Liza Reed, Niskanen’selectricity transmission research manager for climate policy. “The reason that we raise participation up to an equal level with the other Ps … is that groups are really siloed in each of those policies right now. There is stakeholder engagement in planning. There is stakeholder engagement in permitting. There is stakeholder engagement in paying. But different stakeholders get brought in at different points, and that’s when groups start getting frustrated. And I think when folks hear the word ‘participation,’ they think angry town halls and lawsuits. But the whole point of bringing participation into a consistent process is to avoid that.”
Lawrence Berkeley National Laboratory’s Joseph Rand offered an observation from his analyses on the siting and community impacts of large-scale wind and solar.
“What the wind energy developers have learned over time is that we need to move away from a process that people call ‘decide, announce, defend,’ [to one] called ‘consult, consider, modify, proceed,’ so that you’re meaningfully engaging local stakeholders in that process and being open to actually modifying your proposal,” said Rand, senior scientific engineering associate for the lab’s Electricity Markets and Policy Group.
“What has worked well? When you get consensus, it’s easy for it to work well,” said Ted Thomas, chair of the Arkansas Public Service Commission. “What drove the [MISO] MVP [Multi-Value Project] process was it started with the governors. So you had a political impetus; you had a homogenous policy across the region [MISO North]. You also didn’t have an Order 1000, so the incumbent utility knew that if projects were built that it was going to their rate base; that they [MISO] weren’t going to bid it to somebody else. So you had to political push of the governors, and the political push of the utilities. It created consensus.”
In contrast, Thomas said, the failed 700-mile HVDC Clean Line transmission project from Oklahoma to Arkansas, which the U.S. Department of Energy agreed to support, “had higher negatives than gonorrhea.”
“We have battle scars from that,” joked Michelle L. Manary, acting deputy assistant secretary for DOE’s Energy Resilience Division.
To avoid that problem in the future, Manary said DOE will focus not on transmission corridors but on specific projects.
“It’s much easier to study a specific project,” she said. “And I think it’s easier also for the states and utilities to comment on it and coordinate and facilitate with it because they know what we’re talking about — not just a broad swath of land.”
Thomas said FERC should be “very cautious” in using the backstop siting authority it received in the Infrastructure Investment and Jobs Act.
“I think you want a pretty recalcitrant state — a situation where it’s pretty clearly against the public interest,” he said. “Because if you do that push, there’s going to be a push back.”
Go Big
Grid Strategies’ Jay Caspary, a former SPP planner, complimented the RTO and MISO for their Joint Targeted Interconnection Queue (JTIQ) study, which identified seven 345-kV projects totaling $1.65 billion on their seam. But he said the RTOs should consider double-circuit lines instead of the current plans for single circuits. “What we found from the MVPs — as well as the priority projects in SPP and other projects that have been approved — is they’re all oversubscribed within one or two years of going into service,” Caspary said.
Juan Hayem, vice president of interconnections and grid analysis for Invenergy, likened RTOs to slabs of concrete on a highway, which are “very hard and very tough.”
“But the middle [of the seam] should be like an expansion joint that allows the two systems to work together properly. I think some of the issues that we’re seeing right now is the expansion joint is missing and the two slabs of concrete are hammering at each other every time something changes, creating disruptions for everybody. So I think there’s a need to have that soft area there at the seams that allows for the proper coordination, the proper definition of projects.”
Resilience
ConsultantAlison Silverstein said grid planners concerned with resilience to climate change are “drawing the aperture too small.”
“The reality of climate change is such that we need to be thinking about resilience from the customer up, and for an entire set of systems and communities that are much bigger than just the grid,” she said. “When you look at the magnitude and ferocity and frequency of Hurricane Ida, Hurricane Harvey, California wildfires, Winter Storm Uri — all of these things are orders of magnitude worse than anything we ever designed most of the assets on. … We designed this grid for Ozzie and Harriet when we are facing Mad Max, and our systems are caving again and again under the magnitude of the storms that are hitting them.
“So planning how to improve the power system for resilience really needs to start with how do we protect customers against all of the things that are going to go bad,” she added. “Let’s start by protecting customers with energy efficiency and a whole lot of distributed assets. Not just community solar, community storage; a whole lot of things: community warming centers so that people can survive while you’re trying to put the grid back together.”
AUSTIN, Texas — Triple-digit temperatures continue to roast the state, where it is so hot that some roads are literally melting.
It’s so hot that Austin’s El Arroyo restaurant marked the city’s record-breaking 18th day above 100 degrees Fahrenheit on Thursday by using its famed sign, always good for a daily laugh, to vent about the ridiculous heat.
ERCOT’s meteorologist stopped just short of saying the state will see record heat this summer.
“I avoid saying ‘guarantee,’ but this is as close as you’ll get from a weatherman,” Chris Coleman told ERCOT’s Board of Directors on June 21.
Coleman said Texas’ weather is “running hotter” than it was at this same point in 2011, the state’s hottest and driest summer on record. With the state coming off its warmest April and second-warmest May on record, Texas should “approach” 2011’s extremes if summer continues with very limited rainfall, he said.
Unlike last summer, highs will frequently exceed 105 F, Coleman said. Austin has already broken 100 F more than 21 times this month, a record.
“It would be very bold to say we’re going to beat 2011, but everything now is falling into place,” he said. “We’ll at least challenge the record set in 2011.”
The high temperatures have resulted in record demand for ERCOT. The grid operator has set four new records this month for peak demand, the latest coming Thursday when it hit 76.6 GW. The old mark of 74.8 GW was set in August 2019; ERCOT has projected the system would reach of peak of 77.3 GW this summer.
ERCOT has about 91 GW of capacity available when every generator is running. It has been operating with a cushion of up to 6.5 GW of reserves to ensure there is enough power to meet demand as part of its conservative operations posture.
An Austin restaurant’s sign reveals how Texans feel about the summer weather. | El Arroyo
Peter Lake, chair of the Texas Public Utility Commission, said during a hearing before the Texas House of Representatives’ State Affairs Committee on Wednesday that ERCOT would have been “on the brink of rolling blackouts” six times in the last 12 months had it not built in the extra margin.
ERCOT has yet to issue an operation alert this summer, though interim CEO Brad Jones did ask Texans to manage their consumption last month in what was later termed a request. Several retail electric providers on Friday also sent emails to their customers asking them to conserve electricity during the afternoon.
“ERCOT is monitoring conditions closely and will deploy all available tools to manage the grid reliably,” the grid operator said in an email Thursday.
Since April, it has issued four operating condition notices, its lowest-level communication to the market in anticipation of possible emergency conditions. The latest was issued Thursday and expired Sunday.
The National Weather Service said a tropical low is expected to bring rain to the Gulf Coast and Central Texas this week, lowering temperatures to the low 90s and 80s and offering some hope the heat will relent.
“You’re going to need something to stop [the heat],” Coleman said. “Rainfall, either a series of fronts bringing 2 to 4 inches of rain multiple times, or a hurricane. But it’s pretty hard to get fronts past June.”
Indeed. According to the Climate Prediction Center’s initial outlook for July, it will once again be a hotter-than-normal month.
ARLINGTON, Va. — You’d be hard pressed to find a bigger booster of grid-enhancing technologies (GETs) than former SPP planner Jay Caspary, now vice president of consultancy Grid Strategies.
Speaking at the Infocast Transmission & Interconnection Summit last week, Caspary used the adjective “great” to describe topology optimization, storage as transmission and the ability to redeploy GETs at different spots on the grid.
“And that’s great … because congestion is going to move as we start building the grid,” he said. “So we can move this stuff around to where it’s most effective.”
Several other speakers — but not all — shared Caspary’s enthusiasm during the three-day conference.
Bhaskar Ray, vice president of development and interconnection engineering for Q CELLS USA, said planners should consider dynamic line ratings, which have proven valuable in operations. “I think we need to take a closer look in the planning mode to see if we can squeeze out another 10 to 15% of the transmission” capacity, he said.
Kenneth Jennings, general manager of renewable integration and operations for Duke Energy (NYSE:DUK), said he’s looking forward to the comments on storage as a transmission asset (SATA) in FERC’s June 16 Notice of Proposed Rulemaking on generator interconnection (RM22-14).
“I think it’ll be interesting to see what the comments are around transmission alternatives as far as the solutions to solve an overload,” he said. “I think that might open up an opportunity to look at storage differently perhaps than we do today. In general, we think about storage as requiring an interconnection request. It may make sense not to have an interconnection request for storage if it’s solving an overload.”
Caspary also sees an increasing role for SATA. “I think we need to consider that more and more to help create capacity on a system where we need it in the near term.”
He said he’s happy that FERC proposed requiring transmission planners to consider power flow controllers — phase-shifting transformers and phase angle regulators — that have been used on the grid for decades.
He also cited research that found replacing existing lines with advanced conductors could allow the addition of up to 30 GW of renewables to the system.
“We’re going to have to replace a lot of the existing wires on our transmission system over the next decade; I think we’ve estimated maybe 200,000 miles of lines [and] conductors that are going to reach their end of economic life in the next decade. That’s a lot of opportunity to increase capacity in existing corridors and leveraging existing structures,” he said. “Let’s be smart about this.”
But Bart Franey, director of transmission business development for National Grid (NYSE:NGG), was much less bullish than the other speakers, saying GETs will be limited to a “niche role.”
“DLR is not a substitute for rebuilding a line. When you have a 300% thermal overload on a light load day, you’re not going to put in DLR to fix that problem. I think, though, that it can work for minor overloads or as a stopgap solution. Power flow control devices [are] very, very handy, provided you have a parallel line where you can shunt the power over to it. … Advanced conductors … also have a specific application. It’s hard to put advanced conductors on a 100-year-old tower, because it can’t hold the tension. So I think there is a niche role.”
Franey shares the enthusiasm for storage as transmission, however. “I think there’s great opportunity that hasn’t really been tapped into,” he said. “I really think that there are just so many operational, reliability, transmission-type products that storage can offer in one setting and through some clever operations. I think that is going to be a key to an [non-wires alternative] type solution.”
FERC Commissioner Allison Clements said there is “more to come” from the commission on SATA. “Don’t take that as the commission plans to take action on that in the near term,” she cautioned. “I think there is a need to continue to think along those lines to see where the commission has landed in past decisions, and where we should go from there.”
States Want to Deploy More Storage, but Developers Call for Better Planning Tools, Valuation
WASHINGTON — Michigan’s new roadmap for energy storage has set ambitious targets for the state: 1,000 MW online by 2025, 2,500 MW by 2030 and 4,000 MW by 2040.
In Colorado, the state is targeting an 80% reduction in greenhouse gas emissions by 2030, which could trigger “investments of close to $12 billion in wind, solar, storage, peaking capacity and transmission,” according to Eric Blank, chair of the state’s Public Utilities Commission.
But for regulators like Blank and storage developers speaking at the American Clean Power Association (ACP)’s Energy Storage Policy Forum on Wednesday, meeting such targets presents a range of problems, from declining capacity values of projects pairing solar and storage to the challenges of financing storage in restructured markets.
“Solar just falls off more quickly than the peak demand,” said Blank, who appeared at the forum via a video hookup. “So, we’re finding reduced capacity value for both solar-plus-storage, and roughly every 5 to 10% increase in penetration reduces the capacity value by 20% … and we’re now seeing values at 70% coming down more towards 50%.”
Those figures raise a critical question, Blank said. “Is there a real limitation to how much [solar and storage] we can do?”
For Julian Boggs, manager for regulatory and policy affairs at Key Capture Energy, a New York-based storage developer, lower capacity values mean projects may not pencil out, especially in states with restructured markets.
Key Capture has been successful with projects in vertically integrated markets, Boggs said, because it has been able to “internalize a lot of the system optimization benefits in the [integrated resource plan] modeling, in looking out [at] your system over 20 years. … But it has been a huge challenge in restructured states. How do we finance given the capacity values and the energy values and whatever you can skim off energy and ancillary services markets?”
States may have aggressive climate goals and want to “deploy, deploy, deploy,” he said, “but how do you finance projects? How do you get long-term support? … We need to start thinking differently about how we use state support to fill in the missing money effectively in these restructured markets where the wholesale markets aren’t delivering the revenue piece.”
Similarly, Ted Wiley, president and chief operating officer of storage developer Form Energy, said utilities and regulators must also think differently about their long-term planning processes. With backing from Bill Gates’ Breakthrough Energy Ventures, Form is developing a long-duration technology that, Wiley said, could offer up to 100 hours of storage to provide resilience and reliability to the grid.
“There’s a whole host of other technologies that are being developed that are the next wave of storage. We need to be included in the planning process before we reach maturity in order to be a factor,” he said. “That planning has to happen now; [it] has to be a new kind of planning.”
Michigan Public Service Commissioner Katherine Peretick said that whatever the technology, valuation will be key to forward planning.
“If you have the right value for the technology that’s in front of you, you’ll pay for the services you want,” she said. Utilities need to “make sure that they are properly valuing the storage asset, both for the value it can provide to the grid, as well as how much it costs to operate.”
“Both sides of that coin are really necessary to make sure than when you plug that into the IRP model, it’s coming out with the right results,” she said. Developers will need to work closely with utilities to get the input numbers right, she said.
Not Ready for 100-hour Storage
While rising prices and supply chain and interconnection delays are expected to slow growth in the U.S. energy storage market this year, the sector scored a record first quarter, according to the most recent Energy Storage Market Monitor from ACP and industry analyst Wood Mackenzie. Total installations — including residential, nonresidential and grid-scale storage — totaled 955 MW/2,875 MWh, about a fourfold increase from Q1 2021, the report said.
That growth would have been even higher, but 1.2 GW of grid-scale projects that were originally scheduled to come online in the first quarter have been delayed, although about three-quarters are still slated to come online this year, the report said.
Grid-scale solar-plus-storage projects took a hit from the recent procurement bottleneck caused by the U.S. Commerce Department investigation of solar imports from Cambodia, Laos, Thailand and Vietnam. The impacts to project pipelines could continue into 2023, despite President Biden’s recent action to waive duties on solar imports from those countries for two years, the report said. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)
What the figures also show is that the market thus far is focused on shorter-duration uses of storage — an average of three hours — provided by lithium-ion batteries.
From a planning perspective, regulators and utilities are not ready for 100-hour storage, Colorado PUC Chair Blank said. In Colorado, “it’s literally outside our [electric load calculation] studies, which end at 16 hours.”
But, he said, Colorado does have a new program that will pay above-market rates for innovative technologies not yet at scale. But, he cautioned, in such cases, “the technology risks have to be on the vendor or the technology provider, and not on the customer or the utility. So, the form of the transaction shouldn’t be rate-based; it needs to be off-take.”
For Wiley, a new approach to planning should begin with asking, “What is the grid we are trying to build out? What kind of planning tools do we need for that?”
He also believes that the “levelized cost of electricity is no longer the metric we should be looking at. When evaluating storage, we should be looking at a value created at the portfolio level by an asset that allows and optimizes the portfolio, optimizes the generation, transmission and distribution [systems] across all of the asset classes.”
Clean Capacity
Key Capture’s Boggs said states may need to develop a “clean capacity” renewable energy credit to help them meet aggressive storage targets, like Michigan’s or Colorado’s.
Massachusetts’ clean peak standard — incentivizing technologies that can provide clean energy during times of peak demand — is “a halfway evolution … really still based on the REC framework,” he said. But the clean peak approach is still “incentivizing storage only to discharge during certain hours versus doing whatever is most valuable for the grid,” he said.
Blank sees RTO wholesale markets going to a “direct procurement-type approach” for energy storage. “These markets just fundamentally overpay for energy and underpay for capacity,” he said, so relying on a REC-type approach would be “a heavy lift.”
But both Boggs and Wiley argued that storage should be classified as a clean capacity resource.
“It’s certainly not a great idea from a policy perspective to be buying megawatt-hours from storage,” Boggs said. In using storage as capacity, “you’re buying the value of having a clean, flexible resource that is able to respond and optimize the system in any given number of circumstances and participate, whether it’s an ancillary services market; an energy market; whatever the market is [that] is most needed for you to participate in.”
The target for storage, said Wiley, “is to be replacing fossil-based assets that are providing capacity. So, in my mind, that leads me to a 24/7 type construct … a 24/7 carbon-free, clean capacity asset that can replace a fossil asset. That’s what we’re going for.”
Rhode Island Gov. Dan McKee’s proposed legislation authorizing a new offshore wind procurement passed the General Assembly on Thursday and is now on the governor’s desk for his signature.
McKee asked sponsors Sen. Dawn Euer (D) and Rep. Arthur Handy (D) in March to introduce the legislation (S2583/H7971), which the governor said at the time would further the “state’s position as the North American hub for industry activity.”
The House Corporations Committee on June 21 recommended that the House pass the bill with amendments that include increasing the original proposed 600-MW procurement to between 600 and 1,000 MW and directing Rhode Island Energy (RIE) to issue a request for proposals by Oct. 15.
“The offshore wind industry is driving investment in job growth in the local green economy, and this is a good bill that moves us in that direction,” Rep. Joseph Solomon (D), chair of the Corporations Committee, said on the House floor.
RIE would evaluate developer bids on environmental and fisheries impacts, economic benefits, and diversity, equity and inclusion measures. Each RFP would need to include a plan for enabling “historically marginalized communities” to access employment and vendor opportunities related to the project.
The bill would also give the Public Utilities Commission the authority to rule on disputed contract terms, if any occur during negotiations, and direct RIE to secure a final contract.
New procurements under this legislation, together with the already-commissioned 30-MW Block Island Wind Farm and the planned 400-MW Revolution Wind project, could provide 50% of the state’s estimated energy needs, according to a statement from the House.
The legislature also sent a bill to the governor on June 21 that would amend the state’s Renewable Energy Standard to require 100% of electricity to come from renewable sources by 2033.
ARLINGTON, Va. — When comments are filed in August on FERC’s transmission planning and cost allocation rulemaking, one issue sure to generate controversy is the commission’s proposal to abandon Order 1000’s competition measures.
Comments on FERC’s April Notice of Proposed Rulemaking (RM21-17), which would allow incumbent transmission owners a federal right of first refusal (ROFR), are due Aug. 17, with reply comment due Sept. 19. The NOPR would allow incumbents to exercise the ROFR on regional projects on the condition that they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project. (See ANALYSIS: FERC Giving up on Transmission Competition?)
Last week the Electricity Transmission Competition Coalition, a group of industrial consumers and others, asked the chairman and ranking members of the U.S. Senate Finance Committee to oppose FERC’s proposal, saying transmission competition was essential to respond to electricity price inflation. The issue also was the subject of debate last week at Infocast’s Transmission & Interconnection Summit.
FERC said it was changing course because it feared that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission. Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, the commission said. Regional transmission facilities subject to competitive procurements represent only a small portion of transmission investment in recent years, it said.
Commissioner Allison Clements defended the change in remarks at the transmission summit June 21.
“When you look at the record and the lived experiences under Order 1000, you see that the attempt at opening up regional transmission developments to competition had mixed results at best,” she said. “And so we were trying to find a way to mimic the impact of competition to some extent to get cost savings for customers outside of the approach that was taken in Order 1000 and faced a lot of barriers.”
She said the specifics of the new approach will be spelled out based on comments in the docket and at a technical conference Oct. 6 (AD22-8). “We are thinking about big concepts like independent transmission monitors and what role they might play relative to help managing costs,” she said.
Erik Heinle, D.C. Office of the People’s Counsel | Jay Caspary
During a panel discussion later, Erik Heinle, senior assistant people’s counsel for federal affairs and wholesale markets for D.C., called the ROFR proposal “an unfortunate … step backwards.”
“I think we all can agree that that competitive wholesale markets have really brought enormous benefit, both to suppliers and to load. And I think it’s unfortunate, from our perspective, that we don’t use those same tools in transmission planning and bring the same benefits of competition to transmission planning, because we can see not only lower costs, but potentially better solutions to address transmission issues.
“We certainly understand that Order 1000 hasn’t worked as well as the commission hoped,” he added. “But that doesn’t necessarily mean we give up on the goals of Order 1000. Instead, [we should] find ways to double down and improve those goals.”
But Brian C. Drumm, representing Fortis’ ITC Holdings (TSX:FTS), which owns 16,000 circuit miles of transmission in the Midwest, called Order 1000 “a failed experiment,” saying competition has delayed transmission projects without bringing savings to ratepayers.
“The MISO [Multi-Value Project] portfolio in 2011 was the last substantial regional build out in MISO. And I think that’s a direct result of this Order 1000 imposition of competition and competitive bidding,” said Drumm, ITC’s director of regional policy and RTO engagement.
Brian C. Drumm, ITC Holdings | Jay Caspary
Drumm said projects in MISO’s proposed $10.3 billion long-range transmission plan that will be subject to competitive bidding will take two years longer to complete than projects that are exempt. In May, the RTO asked FERC’s permission to change its process to exclude “short segments and conductor-only” work from competitive bidding eligibility (ER22-1955). (See “Competitive Bidding Question Remains Open,” MISO Makes Business Case on Long-range Tx Plan.)
“To the extent you can start building on a large scale and regional basis, you’re going to capture economies of scale that RTOs, in particular, are really well suited to deliver,” Drumm said. “But for those [projects that are competitively bid], there’s a two-year delay for them to get into service; that delay results in increased costs to ultimate consumers. … It potentially could impact the operation of the portfolio as well.”
Drumm declined to say if transmission providers deserved blame for obstructing competition.
“FERC was trying to get more productivity and efficiency, lower costs into the transmission planning of transmission projects. And ultimately, what we’ve seen is … a lack of collaboration amongst highly regulated utility entities and transmission providers that previously worked well together,” he said. “I’m not really sure of all the reasons, but I do know what the results were: This resulted in delay and increased costs. So [the blame is] kind of irrelevant.”
MIT economist Paul Joskow issued a working paper in 2019 that concluded “the experience to date is sufficiently promising to consider expanding the use of open competitive procurement solicitations for transmission projects.”
The Brattle Group issued a report the same year for independent developer LS Power that concluded that competitive solicitations saved an estimated 20 to 30% of project costs compared to traditionally developed projects. LS Power won PJM’s first Order 1000 competitive project, for upgrades to Artificial Island in New Jersey, after promising a cost cap.
“Thirty percent savings … it’s hard to say that’s a failed experiment,” said Jennifer Chen, senior manager of clean energy for the World Resources Institute. “Maybe there are places where we can compromise … but I would say we should do our very best to make this process as competitive and transparent as possible, and make sure that we are investing money wisely.”
Drumm’s comments also drew a rebuttal from Ali Amirali, senior vice president of Starwood Energy Group Global. “For those who don’t believe that [competition] was working, come talk with me and LS Power, and we’d be more than happy to show you where it is working.”
[EDITOR’S NOTE: A previous version of this story incorrectly stated that initial comments on the NOPR are due by July 18. Comments were initially due by that date when the NOPR was first approved, but on May 25, FERC granted a request for additional time, setting a new due date of Aug. 17.]
