ATLANTIC CITY, N.J. — Spurred by the rapid rise in renewable energy project planning and declining battery costs, storage development is growing nationwide, but states need to ensure that they fund, shape and incentivize projects that contribute to their emission-reduction goals, a speaker told New Jersey’s Clean Energy Conference on Oct. 4.
States such as New Jersey, which is in the process of planning its first large-scale electricity storage incentive program, need to focus not only on stimulating storage capacity development but on making sure that the resulting projects help cut the use of fossil fuel generating plans, Todd Olinsky-Paul, of the Clean Energy States Alliance, said on a panel at the conference, organized by the New Jersey Board of Public Utilities (BPU).
The goal is “not just to get the storage there; it’s to get it there and link it to whatever policy targets or aspirations the state has,” Olinsky-Paul said. Projects need to charge up their batteries with cheaper, off-peak power and be ready and available to discharge when demand is greatest, to help negate the need for utilities to fire up fossil-fueled peaker plants, he said.
His comments came amid what he said is a dramatic increase in storage development in almost all states. Ten years ago, he said, he could have summed up national storage development activity by citing a handful of programs. “But things have exploded so much in policy in the last few years that I can no longer do that,” he said.
The rapid advance of the sector prompted another panelist, Brian Kauffman of Enel North America, to advise states looking to jumpstart or boost their storage capacity that they no longer need to think of developing a pilot program first.
“There’s a lot of examples of how to structure them and what results in customer uptake. There’s a very mature ecosystem of competitive purchase market participants,” Kauffman said.
“A lot of times, these pilot programs are set up where you don’t really know what the cost of doing the project is going to be [or] who’s going to participate in the project; you just want to learn,” he said. But now, “you have thousands of customers who are participating in programs across a dozen states or so.”
Finding the Right Incentive Level
Storage is widely seen as a paramount element needed to manage electricity supply as intermittent renewables become increasingly dominant.
The conference came just after New Jersey, admitting that it had lagged state ambitions in developing storage capacity, released a straw proposal on Sept. 27 that outlined a plan to stimulate the development of standalone storage capacity by offering incentives for grid-scale and consumer-level projects. (See NJ Offers Plan to Boost Lagging Storage Capacity.)
The BPU’s plan, known as the Storage Incentive Program (SIP), would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.
Jim Ferris, deputy director division of clean energy at the BPU, told the conference that the fixed incentives would be awarded using a “declining block structure” that has worked in other states. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower rate.
“In that way we are providing certainty to the market, but also finding the right incentive level,” Ferris said. “Obviously, if a particular block does not fill at that incentive level, we will have the opportunity to either extend that particular block and incentive or even go back and increase the incentive.”
The agency also has sought to ensure that it does not provide financial support for a project that “just sits unused,” he said. To receive the incentive, “the device will need to be available for 95% of hours,” he said.
The pay-for-performance incentive, which is based on PJM marginal carbon intensity data, is designed to tie the BPU’s incentive to demonstrable emissions reductions, Ferris said.
“So we would be incentivizing when storage is charged when emissions are low, and discharged when emissions are high. And that delta will yield an incentive,” he said. The performance incentive for distributed projects is based when the project injects energy into the system or is used to reduce the use of energy at the request of electric distribution companies, a strategy used in programs in Connecticut and Massachusetts, he said.
Monetizing Storage
States have taken different approaches in seeking to stimulate storage development, CESA’s Olinsky-Paul said. They include mandating a certain amount of storage by a particular date, or just setting a target capacity procurement, he said. Nine states have set a target. Among them are California, shooting for 1,825 MW by 2020; Massachusetts, with 1,000 MWh by 2025; New York, with 3,000 MW by 2030; and Oregon, 5 MWh by 2020.
He displayed a slide that showed more than two dozen states have taken three or more types of action to plan for storage development, including studies and investigations, new policies and regulations, and financial incentives and rates. And all but three states have taken at least one step toward storage development.
One difficulty in stimulating storage development, according to the BPU and panelists at the conference, is that storage devices are difficult to “monetize,” which in turn puts the onus on state support. For that reason, the BPU proposal encourages investors in storage projects to pursue “value stacking,” or looking for several revenue streams to support the project.
While storage projects can provide benefits such as reduced electricity costs and emissions, “the current revenue streams, as in a lot of places in the U.S., including New Jersey, really aren’t sufficient now for storage to scale,” Enel’s Kauffman said.
Olinsky-Paul said one of the “best practices” that states should follow is identifying the attributes of a project that are “priced” or monetizable. He cited the example of a service station owner who installs a storage project on the property.
“So when the grid goes down, I’m able to fuel customers’ cars, first responder vehicles; that’s providing value to the community,” he said. “Did I get paid for it? No. Because there is no market for resilience. I can’t bid that service into a market or sell that service to utility as a backup power service.”
So the state needs to look at the balance of monetizable and non-monetizable benefits and work out “how are we going to provide that gap funding somehow to encourage that market to develop,” he said.
For the operator, the monetary benefits depends on the business model that the storage operators develops, Olinsky-Paul said. For example, the operator may use an arbitrage model of charging up the storage at night when the power price is low and selling the energy at peak hours when the price is higher, he said.
The operator of a solar farm may find storage provides “capacity value,” which in turn provides a financial revenue, he said.
“Solar by itself doesn’t have a lot of capacity value, because it doesn’t have an on-off switch; you can’t rely on it,” he said. “So you’ve now firmed the solar power that was previously variable. Well, there’s a value to that. If you’re bidding that power into a wholesale market, and they want firm power, they’re going to pay more for it if they know that you can turn it on and off than if you are just at the mercy of the clouds.”
Rensselaer, N.Y. — NYISO is proposing to broaden its rules for including projects in the base cases of transmission studies because of an increasing risk that projects studied in one process may affect those studied in others, the ISO’s Thinh Nguyen told the Transmission Planning Advisory Subcommittee Oct. 3.
Because of timing issues, projects being studied in the ISO’s transmission interconnection procedures (TIP) do not always meet the base case inclusion rules of the class year study, or vice versa. As a result, Nguyen said, there may be interactions among these projects that need to be studied.
Nguyen also said the chance of this issue between studies being conducted in parallel has increased with the rise in requests entering the NYISO interconnection queue as well as the increasing number of distribution-level projects.
One proposed enhancement to the ISO’s rules would revise the ISO’s base case inclusion rules to specifically refer to projects being studied outside of the ISO’s procedures that a transmission owner identifies as having advanced sufficiently to be considered “firm” in the TO’s planning its local system.
Another change would add tariff provisions on the use of sensitivities and true-up studies in the TIP facilities studies to account for interactions with class year projects that could require the same or similar upgrade facilities. Following the completion of a class year study, the ISO will conduct a true-up to reflect class year projects accepting or rejecting their cost allocations and posting security to continue development.
Although the current tariff allows the ISO “flexibility” to account for these timing issues, the ISO said explicit tariff provisions detailing the use of sensitivities would improve coordination between the study processes.
The ISO plans to present proposed tariff revisions later this month or early in November.
RNA Draft Report Findings
The ISO presented findings from its fourth draft of the 2022 Reliability Needs Assessment (RNA), which did not identify any reliability needs for the 10-year study period but found that resource adequacy and transmission security margins are tightening over time.
The RNA report identified the risk that extreme weather events, such as heat waves and severe storms, could result in significant reliability deficiencies reducing the ability to serve demand, particularly in New York City.
The RNA also evaluated the impact on the system if 6,300 MW of gas-fueled generation became at risk due to fuel shortages during winter peak conditions. The RNA found that if these generators are unavailable during a peak winter in 2032, reliability would be diminished but still within the loss-of-load-expectation criterion. However, reliability would not meet statewide system margin under expected winter weather conditions by winter 2031-32, presenting a significant future risk.
The ISO told the committee it made small changes in response to stakeholder comments and questions since the second draft of the RNA was presented at the Sept. 1 TPAS meeting. (See “RNA Draft Report Finds No Immediate Needs,” NYISO Proposes Fixes for Interconnection Backlog)
The ISO plans to bring the RNA to votes at the Operating Committee Oct. 13 and the Management Committee Oct. 26 before submitting it to the NYISO Board of Directors for final approval in November.
AUSTIN, Texas — The Gulf Coast Power Association’s 37th annual fall conference, held in-person for the first time in three years, drew 685 registered attendees here last week. Strangely, that was the exact number of registrations the GCPA had for the same event in 2019.
When not renewing friendships and sharing handshakes and embraces with those they hadn’t seen in years, attendees were treated to panel discussions among lawmakers, market participants and industry experts on the ERCOT market, an oral history of the Texas grid operator, and a reenactment of the historical debates between Abraham Lincoln and Stephen Douglas.
Taking it all in was freshly minted ERCOT CEO Pablo Vegas, a surprise guest to the proceedings in just his second day on the job. He was shepherded during the conference’s first full day by Bill Flores, vice chair of the ISO’s Board of Directors. Vegas listened intently as the Joneses — Sam, ERCOT’s first CEO; Brad, its retiring interim CEO; Liz, Oncor’s regulatory affairs lead; and Dan, a respected energy consultant who helped create Texas’ competitive market — reminisced about their roles in ERCOT’s various market designs and how often their paths crossed at the ISO, Public Utility Commission and elsewhere in the industry.
Vegas seemed aware of the high expectations he faces and the responsibility he is undertaking.
“To think about the history of this institution that I’m now going to have the privilege to lead … each of the leaders up there have played a significant role in making and [preparing ERCOT for change],” he told RTO Insider. “It’s not so much a passing of the torch but just continuing to make sure that we all understand where it’s been, why it’s lit, and why that’s important.
“It’s just exciting to be a part of the next big change and big evolution that ERCOT has been going through, decade after decade over the years, and it’s great to be a part of this one. I can tell that there’s going to be a lot of help from the industry, a lot of suggestions, and I’m just looking forward to working through all of those together with such a great team.”
Introduced by Flores for a few opening comments to the audience, Vegas said he was “thrilled … honored and privileged” to be joining Team ERCOT and that he looked forward to working with the “incredible professionals” in the ballroom. Vegas invited those he did not know from an earlier stint in Texas to come meet him. (See Vegas Plans to ‘Engage Heavily’ in ERCOT Changes.)
“All I can say is, ‘Wow, what a time to be coming back into Texas,’ with what’s going on in the market and what’s going on in the economy,” he said. “I can’t remember a more exciting time to be in this industry.”
Flores Says Vegas ‘Checked All Boxes’
Flores, who led the ERCOT board’s search committee for Jones’ successor, told RTO Insider that Vegas checked all the boxes the group was looking for. He said Vegas stood out early after the committee initially identified 107 candidates to become the grid operator’s fifth full-time CEO.
“It quickly came down to a small handful of people. We were looking for somebody with an engineering technical background, somebody with good leadership attributes, including a selfless servant leadership style. We were looking for someone who had senior executive experience … and to a lesser extent, somebody who already had experience with the Texas market,” Flores said, nodding to Vegas’ two years as COO of American Electric Power’s AEP Texas subsidiary.
Told that it appears he has been a quick learner of ERCOT’s operations and functions, Flores said, “I’ve been a real nerd about this.
“I’ve read a lot of books; I have listened to tons of podcast. I spend a lot of time with Woody [Rickerson, ERCOT’s vice president of system planning and weatherization] and the gang, and I’m still not done yet.”
A five-term Republican member of the U.S. House of Representatives, Flores was appointed to the ERCOT board last year and serves as its vice chair. A certified public accountant, he has a background in the oil and gas industry. During his keynote address, Flores warned of the danger of relying on a single fuel, as Europe has discovered with Russian natural gas after its invasion of Ukraine. However, he also noted he is the largest residential solar user in his home county, and he extolled an “all-of-the-above” approach to ERCOT’s fuel mix.
“One of the things I’ve noticed in environmental analysis today is that when you look at fossil generation, it’s looked at from end to end,” Flores said. “When you’re looking at other forms of generation, it’s just from when you turn it on to when you turn it off. Every source of generation needs to be looked at end-to-end on the environmental and emission scale.
“The bottom line from a policymaking perspective is that we need all-of-the-above solutions that have balance, that follow the laws of nature with respect to electricity, that follow the laws of economics,” he said. “We’ll have better policy outcomes when we follow those laws, versus what we as humans think we can do.”
GCPA Members Honor Jones
GCPA members and conference attendees honored Brad Jones with an extended standing ovation after his panel discussion with three other Joneses ended.
GCPA President Mark Dreyfus, who represents commercial consumers on ERCOT’s Technical Advisory Committee, recalled his more-than-25-year association with Jones. It began when Dreyfus was a PUC staff member and Jones was the “lowest guy on the totem pole” for TXU, Vistra’s predecessor.
“His job, as far as I could tell, was to chase after us following a PUC open meeting to find out exactly what the commissioners had decided so he could report back,” Dreyfus said. “I really liked that Brad Jones back then.”
Jones rose through the ranks at TXU and played an integral role in designing ERCOT’s competitive market. Like Dreyfus, Jones presided over GCPA. He joined ERCOT as COO and then “packed up his cowboy boots,” as Dreyfus said, and left Texas for a short stint as NYISO’s CEO.
“But I know he was lonely for home and family,” said Dreyfus, who visited Jones in Albany, N.Y. “He treated me like family and treated me to an insider’s tour of the city: well-cooked sirloin, beer pong and a reggae show.”
Jones left NYISO in 2018 and retired to his home in Austin. That is, until the February 2021 winter storm came within minutes of collapsing the Texas grid, leaving ERCOT and the industry in “disarray,” as Dreyfus put it.
“Who would step up and take on the responsibility of leadership? I can’t think of anyone other than Brad, who brought his experience in the industry, experience in the New York ISO, and that demeanor he has which is so successful with our industry members at the legislature and with the membership of GCPA,” Dreyfus said. “We don’t have a gift card or flowers or custom GCPA cowboy boots, but we do have a reception immediately following where I hope you will take a minute to thank Brad.”
Jones could do little more than laugh and nod his head in appreciation.
“Brad has done a great job of readying ERCOT for this next level of change,” Vegas said after the applause settled.
“[Jones] stepped up at a really critical time for the 26 million Texans that are served by the ERCOT part of the Texas grid and to help keep the team together,” Flores said. “He worked with policymakers and regulators to keep the lights on, so we owe him.
McAdams: Give Market-based Solutions a Chance
PUC Commissioner Will McAdams gave the conference attendees a sneak preview of the commission’s proposed Phase II market design, which the commission continues to plan for a mid-November release. He said the commissioners recognize that the grid of the “very near future” will consist of more renewable and intermittent resources than dispatchable capabilities.
“And that’s fine. We believe, I believe, to cover the variability of intermittent output, we must ensure that sufficient quantities of dispatchable power cover system needs during forecasted high risk periods,” he said in a keynote address. “This serves as the basis of what we’re discussing now. This will allow us to reduce our out-of-market actions like [reliability unit commitments] and replace them with market-based solutions. [As other speakers suggested], this framework will be based on market principles, which I hope will represent the consensus of the commission.”
McAdams said the Phase II market adjustments will encourage dispatchable generators to maintain their facilities, and, if necessary, to replace retiring units with new generation. But, he reminded his audience, the PUC can’t guarantee that new generation will be built.
“We can influence markets, but we cannot command them to deploy capital,” McAdams said. “If policymakers believe that they require a guarantee that new generation be built in order to meet growing system demands, then a policy must be taken up and considered by the state legislature. It is a crossroads … one route stays the course with markets and market-based solutions. The other would instruct the PUC to assume a more command-and-control posture in how electricity is generated and delivered within ERCOT.”
Historically, markets, collective viewpoints and their stakeholders are best suited to adapting to changes, he said.
“As such, I believe that the best way to restore the public’s trust and confidence in our grid is for the public utility commission, ERCOT and our market participants to work together to demonstrate that we can build a policy to achieve maximum grid reliability,” he said, “and at a sustainable cost level to Texas consumers that may endure challenges by the naysayers and detractors and demonstrate to the legislature that this is a market worth saving.”
Texas Politicos Wait on ERCOT Redesign
Count Texas lawmakers among ERCOT stakeholders who are looking forward to the PUC’s release of its Phase II market design, expected in mid-November. The Texas legislature opens its five-month biennial session Jan. 10, and legislators have asked to vet the PUC’s market design before the ISO’s staff begins to implement it. (See Texas Lawmakers to Vet ERCOT Market Redesign.)
“For the most part, we’re all waiting for the next big change,” State Sen. Nathan Johnson (D) said, noting discussions taking place within several Texas energy advisory and reliability committees. “I don’t mean to be dismissive of it being a lot of talk, but because it’s a very important conversation, but we have yet to see the results from it. We have a variety of perspectives. We have competing viewpoints … but as we move into the legislative session, and as we come out of the legislative session, we’re going to have to have some clarity.”
Johnson said legislators, who passed several laws related to the grid’s near-collapse during last year’s winter storm, expected the market design to have been further along that it is now. (See Abbott Signs Texas Grid Legislation into Law.)
“As much fun as it is, this is hard. We don’t have the answer yet,” he said. “We need the confidence of the investors. We’re not going to get there with a bunch of day-ahead ancillary services. We’re going to see some form of a capacity market in our energy-only market. There’s going to be an element of predictability and an agreed-upon predictability standard.”
State Rep. Phil King (R), who represents a gas-rich district, said electric power has been the most complex, competitive and diverse issue he has dealt with in his 24 years at the Capitol.
“I think this is going to be the second most substantive change we’ve made in how we do all this since 1999 … we created a competitive market that was the envy of the world,” King said, referring to Senate Bill 7 that deregulated ERCOT’s wholesale and retail markets.
“From my perspective, it’s how do we make sure that we have enough gas-fired generation that can be built in a way that companies can make a reasonable profit? But how do we incentivize building enough gas-fired power without stepping over that line and entering back into a regulatory market?” King asked. “Renewables have a big place in Texas. I think we can have a really hard discussion about how much that is. Relative to the amount of dispatchable electricity, I think there’s too much. And so how do we incentivize from a financial perspective and a regulatory perspective for gas-fired plants to be built without stepping off that cliff and losing the competitive market?”
“We have to be agnostic about the future,” countered State Rep. Donna Howard (D). “Obviously, we need to have resiliency, and we need to have reliability. It needs to be affordable. We need to have dispatchable [generation] and we need to have predictability. We know that renewables, of course, are predictable [to forecast]. Gas is volatile. We are so fortunate to have the thermal resources that we have … We want to make sure that whatever the market redesign ends up being, that it is going to incentivize whatever it is that will give us the power we need when we need it.”
Lincoln-Douglas? Try Barnes-Stover
Apex Clean Energy’s Mark Stover and NRG Energy’s Bill Barnes did their best to recreate the famed 1858 senatorial debates between Abraham Lincoln and Stephen Douglas, albeit in condensed form. Rather than conduct seven three-hour debates, the two settled for a 30-minute discussion over whether transmission planning and regulatory reforms to relieve congestion are compatible with regulatory design changes to retain and incentivize dispatchable generation in ERCOT’s energy-only market.
“I have made many sacrifices throughout my career for the entertainment of the GCPA audience. This might be a new low or new high, so I hope you guys appreciate this,” Barnes said, donning a fake beard and what passed for a stovepipe hat in his role as Honest Abe. “Abraham Lincoln was like nine feet tall, so you’re going to have to use your imagination.”
“Bill definitely wins the costume category,” admitted Stover, who wore a vest and a long coat. “But at the very least, Bill and I got a jump on our Halloween shopping this year.”
Stover, Apex’s director of state affairs, said in his address that market design and transmission reforms are compatible. If done right, he said, ERCOT’s transmission planning process “can actually bolster our efforts to increase reliability on the ERCOT system, something every stakeholder wants, including the renewable energy sector.”
“If the transmission projects can deliver new wind, solar, storage and, yes, natural gas paired with something that we don’t talk a lot about, increased efficiency and demand response, we can deliver the same amount of power or more at a lower cost than existing fossil assets or new planned large thermal assets,” Stover said. “We need to move away from our just-in-time regime, which is increasing costs on consumers and unnecessarily straining our power grid and keeps a range of benefits from flowing to consumers.”
“Hogwash!” Barnes, NRG Energy’s senior director of regulatory affairs, bellowed after Stover’s close.
“Transmission planning processes and regulatory reforms that create preference for transmission development fundamentally conflict with the foundational principles of an energy-only market and work to defeat the incentives to retain and attractive dispatchable resources,” Barnes said. “Transmission congestion is a design feature of LMP-based markets, not an excuse to endlessly build more transmission lines. These deliberate pricing differences allow for the competitive market to address transmission bottlenecks through redispatch of generation and, if allowed to persist, through private investment, rather than regulated costs to captive ratepayers.”
The audience judged the debate a draw. Douglas narrowly won election to the Illinois U.S. Senate seat up for grabs after the debates. Two years later, though, Lincoln won the big prize when he defeated Douglas in the 1860 presidential election.
Vistra’s Haley Receives GCPA Award
GCPA presented Vistra’s Ian Haley with its emPOWERing Young Professionals Award, as selected by the organization’s board. The award is presented annually to an individual under the age of 40 who has achieved excellence in the power industry, making unique contributions to the success of the electric power market and serving as a role model and leader for others.
Vistra’s senior director of regulatory policy, Haley was described as “an ardent participant in the stakeholder process.” He represents Vistra subsidiary Luminant on TAC and works on several other ERCOT committees, vice chairing the Supply Analysis Working Group.
“I cannot tell you how much I appreciate this,” Haley told the audience. “I’m deeply honored, even though quite a few of you have told me there’s no way I’m under 40. I feel extremely fortunate to work in an industry that I find so interesting and have the opportunity to work with so many people I consider friends.”
“He’s a fellow Tulane graduate,” Vistra CEO Jim Burke said in introducing Haley. “You probably didn’t read that in the bio, but good people come out into Tulane University.”
“Ian has a knack for reaching out across the aisle in the ERCOT stakeholder process and is an adept negotiator,” Ned Bonskowski, Vistra’s vice president of Texas regulatory policy, said in a statement. “Some of his strongest work is when he is forging consensus across disparate stakeholders on contentious issues.”
The award’s nomination criteria includes career progress, industry involvement, leadership development, role model for other young professionals, and expertise, passion and the ability to inspire others.
Stakeholders Endorse 2022 Reserve Requirement Study Results
The PJM Planning Committee on Oct. 4 voted by acclamation to endorse the results of the 2022 Reserve Requirement Study, which would reset the forecast pool requirement (FPR) and installed reserve margin (IRM) for the next three years and determines a recommendation for 2026/27. It would also set a winter weekly reserve target (WWRT) for the upcoming season.
The recommended IRM remains at its current 14.9% for 2023/24 before falling to 14.8% the following year and declining to 14.7% for 2025/26 and the next year. Last year’s study recommended a similar decline, though moved up a year in advance. (See “Reserve Requirement Study Recommends Raising IRM and FPR,” PJM MRC/MC Briefs: Sept. 21, 2022.)
Driven largely by scarce projected capacity available for import during peak season, the recommended FPR for 2023/24 increases under the study, going from 1.0901 in last year’s analysis to 1.093 in this year’s. That moves downward to 1.0926 in 2024/25 and falls to 1.0918 for the following two years.
The study recommends a 27% WWRT during the peak winter month of January, 23% for February — the next highest consumption winter month — and 21% in December. The figure is used to aid PJM in planning outages.
The IRM and FPR are set to be reviewed by the Markets and Reliability and Members committees in October through November and by the Board of Managers in December. The WWRT is scheduled to be voted on by the Operating Committee in November.
Load Forecast Model Recommendations Discussed
PJM Senior Analyst Andrew Gledhill reviewed the recommendations under consideration for the development of a new load forecast model.
The recommendations are derived from a report produced by the consulting firm Itron, which was contracted in April to perform a model review. They include:
replacing annual/quarterly end-use indices with the use of monthly/daily indices, which would allow for the use of more recent data that are more representative of current patterns. Monthly models would also result in heating and cooling figures that are more reflective of the amount of weather variation in each month.
continuing with the current weather simulation approach, but with a shorter historical lookback period of 20 years and seven rotations; 27 years and 13 rotations are currently used.
replacing daily models with hourly load models, which would allow for more flexibility to incorporate future trends and technology, particularly the impact of solar and electric vehicles.
adjusting loads for new technologies through the simulation process, reflecting current knowledge about how behind-the-meter solar and EVs behave and layering those understandings into simulations.
incorporating climate change into long-term forecasts and evaluating long-term temperature trends for each planning zone.
Gledhill said PJM is in the process of evaluating the first four recommendations for the 2023 load forecast and will report its progress to the Load Analysis Subcommittee. The fifth recommendation is expected to take additional thought and engagement with stakeholders, with a tentative plan to incorporate it into the 2024 load forecast.
Poll Opened to Gather Support for Packages on CIR for ELCC Resources
The PC is holding a nonbinding poll to gauge support for the six proposals currently on the table to address capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources. Opened after the committee’s meeting, the online poll closes Tuesday at noon.
The poll asks respondents to say whether they can support each of the packages and, if not, to indicate which of the design components they are against. The packages are composed of five overall components: CIR request policy; CIR verification, testing and retention policy; CIRs in ELCC methodology and accredited unforced capacity calculations; implantation and effective dates; and transition mechanisms.
The sponsors of the packages outlined the changes that the proposals have undergone over the past few months and discussed the effects each would have.
Tom Hoatson, director of Mid-Atlantic policy for LS Power, said his company’s package could continue to change depending on the results of the poll, particularly its CIR request policy, which he said was written to achieve a consensus in prior special sessions and relies upon the same language as one of the PJM packages. Stakeholders questioned what the impact would be should a generator request a higher CIR level than it can deliver under that language.
Responding to questions about the impact of the packages on the cost and timing of the RTO’s interconnection queue restructuring effort, PJM’s Jonathan Kern said the proposals that incorporate higher CIRs into the mix would have an impact on the queue.
Economist Roy Shanker said that any time the order of the queue is changed and applications are moved ahead of each other, the cost allocation changes alongside it, and those who are “jumped over” will face increased costs. The current structure being considered would result in approximately 7,200 to 7,300 MW of projects being given priority status, which would result in an estimated $2 billion cost for applicants in the fast track and Transition Cycle 1, he said. The costs remain unknown for those in Transition Cycle 2, but Shanker said they could potentially face billions in increased costs.
“As long as you don’t change that order, you don’t change that cost,” he said.
Transmission Expansion Advisory Committee
$13M in Tx Projects Discussed
At the Transmission Expansion Advisory Committee meeting that followed the PC’s meeting, several transmission owners presented supplemental projects for the PJM Regional Transmission Expansion Plan.
Baltimore Gas and Electric is planning the replacement of its High Ridge 230-1 transformer, installed in 1960 and in deteriorating condition, at a $7.4 million cost.
American Electric Power meanwhile has several facilities operating on a former practice of applying a double multiplier in the ratings of facilities that connect in a configuration where flow could split between two paths in a station. The company is in the process of applying single-multiplier ratings to all its facilities, but four were flagged in PJM’s 2025 RTEP analysis that could result in violations of NERC reliability standards.
The work would include replacing breakers and associated equipment at the 765/345-kV Marysville transformer, 345/138-kV East Lima transformer, 345-kV Jefferson-Clifty Creek line and 138-kV Olive-New Carlisle line at a $5.92 million cost.
Residential solar-plus-storage systems can in some cases meet nearly all of a home’s “critical load” — including heating and cooling — during extended power outages, according to a study from the Lawrence Berkeley National Lab.
But system performance depends on a variety of factors, including the size of the system, where in the U.S. the home is located, and whether the home uses electric-resistance space heating such as baseboard heaters. The study, which was based on models and simulations, described loads from electric resistance heating as “quite large and more difficult to serve.”
The impact of electric resistance heating was one of the surprises to come out of the study, according to Galen Barbose, a research scientist in the Electricity Markets and Policy Department at Lawrence Berkeley National Laboratory and one of the study authors.
“That was far and away the biggest determinant to the results,” Barbose told NetZero Insider.
Berkeley Lab researchers collaborated with scientists from the National Renewable Energy Laboratory on the solar-plus-storage report, which was published last month. Barbose and Berkeley Lab colleague Will Gorman hosted a webinar last week to discuss the study’s findings.
Behind-the-meter solar-plus-storage systems are gaining popularity among residential and commercial building owners, Barbose said during the webinar.
“That trend is being driven by a variety of factors, but certainly one of the major ones has been concerns around grid reliability and resilience and customer interest in using these systems for backup power,” he said.
Yet there has been little research into how well the systems perform as backup power during extended outages, a question the researchers sought to address.
Simulating Outages
The researchers modeled solar and load profiles and then simulated battery storage dispatch during power interruptions. The study looked at outages of a day or longer. These “synthetic” power outages were examined in every county in the U.S. and for every month of the year.
The study primarily analyzed the expected performance of systems where solar provides all of a home’s annual energy consumption, which Barbose said is “pretty typical” for the systems. Systems with 15 kWh or 30 kWh of storage were compared.
The analysis showed the systems could provide enough backup power to meet “limited critical load” in single-family, detached homes. That load includes refrigerators, lighting, well pumps, and power for computers, internet and cell phones.
“Under a limited critical load scenario that excludes heating and cooling, a small [solar and storage system] with just 10 kWh of storage … can fully meet backup needs over a three-day outage in virtually all U.S. counties and any month of the year,” the report stated.
But if the loads are expanded to include heating and cooling, more variation emerges. A system with 15 kWh of storage would meet a projected 85% of critical load including heating and cooling, averaged across all counties and months. A system with 30 kWh of storage would meet 96% of load on average.
With heating and cooling included in load, the backup performance of solar plus storage dips in the winter in the Southeastern U.S. and the Pacific Northwest, regions where electric resistance heating is common, the study found. In the summer, backup performance falls in the Southwest.
In cities such as Chicago and Boston, many homes use gas furnaces for heating, so wintertime heating doesn’t add that much to the electric load, the researchers said. Furnace fans, which often run on electricity, may contribute to the load.
The researchers plan to take a closer look in the future at backup-system performance in homes with electric heat pumps.
Solar Plus Storage Confidence
The overall results may give homeowners more confidence in solar plus storage as a backup power system, especially if they’re primarily interested in maintaining power to a limited load set without heating and cooling, Barbose said in an email after the webinar.
“In cases where customers want to provide backup to heating and cooling loads, the report shows that this may be possible, but requires careful attention to the size of those loads,” Barbose said.
And providing backup for heating and cooling is easier when homes are energy efficient, he said.
Another surprise to come out of the study was that in most cases, the length of the power outage had little impact on how well the solar-plus-storage systems could maintain backup power.
Average load served dropped from 96% on the third day of the outage to 92% on the 10th day, according to the simulations for a 30-kWh storage system that included heating and cooling. That indicates solar energy would largely be able to replenish battery storage that became depleted.
But the longer an outage lasts, the greater the chance of experiencing a cloudy day or increased load, decreasing the percentage of load met, the researchers noted.
In another piece of the study, researchers looked at how well solar plus storage would have fared as a backup system during outages caused by 10 actual weather events.
During a winter storm that hit Oklahoma in October and November 2020, with outages lasting up to 12 days, the study found a median load served of 98% with a 10-kWh battery and 100% with a 30-kWh battery.
The study calculated a median load served of 100% for either a 10-kWh or 30-kWh battery during the October 2019 public safety power shutoff in Northern California. The outage lasted for up to 4.6 days.
But for Hurricane Florence, which caused outages of up to 10 days in North Carolina in 2018, median load served as calculated in the study was 68% with a 10-kWh battery to 76% with a 30-kWh battery.
“Performance can vary considerably over the course of the event,” researchers noted. For example, solar plus storage performance suffered from lack of sunshine during the first days of the outage caused by Hurricane Florence but recovered in later days.
MISO’s final Transmission Expansion Plan for 2022 (MTEP 22), comprising 382 projects totaling $4.3 billion, earned a hesitant nod from the stakeholder-led Planning Advisory Committee last week.
Four of 11 MISO sectors voted electronically for the annual transmission expansion package while five sectors abstained, some with criticisms. None of the sectors voted to reject MTEP 22.
MISO’s Transmission Owners, Municipals and Co-ops, Affiliates and Independent Power Producers sectors voted in favor of the plan. The RTO’s State Regulatory, Public Consumers, Eligible End Use Customers, Transmission Developers and Environmental sectors abstained.
The Power Marketers and Coordinating sectors didn’t participate. It’s not unusual for the End-Use, Public Consumers, Power Marketers and State Regulatory sectors to abstain or refrain from casting ballots in PAC voting matters. It is unusual, however, for abstentions to outnumber votes in favor of MTEP package recommendations.
The Transmission Developer sector said it abstained because MISO’s $3 billion spend in “other” category projects is large and the grid operator “has not adequately considered regional alternatives that may be more efficient or cost-effective solutions to the identified needs.” The developers also said there’s currently “minimal ability for MISO stakeholders to meaningfully participate in the planning” of projects in the “other” category.
MTEP 22 contains 69 generator interconnection projects costing $547 million; 41 baseline reliability projects at $545 million; and 270 other projects at almost $3.2 billion. The other project category includes TOs’ reliability projects and work needed for load growth and to address existing facilities’ age and condition. Other projects have become the lion’s share of MTEP spending since the 2018 cycle.
The Environmental sector said it took exception to language in MTEP 22’s report. It said MISO should clarify that the changing resource mix “is not driven solely by carbon-reduction goals” and said staff shouldn’t exclusively use natural gas resources as an example of a solution for more available resources.
In the report, the grid operator says it has a responsibility to reliably transition from “today’s resource mix” to “our members’ stated carbon-free goals.” The environmental representatives said MISO should add that the transition is also driven by “economics, state and utility policies, and consumer preferences.”
“If MISO refuses again to meaningfully address these concerns, then we request that the System Planning Committee of the Board of Directors require MISO to address these requests in a meaningful way prior to sending the draft MTEP 22 report to the full Board of Directors,” the sector wrote.
The annual transmission package now advances to the board’s System Planning Committee for consideration. The full board will then vote on MTEP 22 in early December.
Entergy Arkansas’ $122 million Sandy Bayou 500/230-kV substation to accommodate load growth is this year’s most expensive project. It will tap into the utility’s existing Driver–Shelby 500-kV line.
That second-most expensive project is Ameren Missouri’s need for $120 million of new static synchronous compensators necessary to reinforce the system when the utility retires its 1.2-GW Rush Island coal power plant. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)
MISO project manager Sandy Boegeman said MTEP 22’s costs are typical when compared to other recent MTEP packages. She said age and condition drove many of the reasons behind the projects.
MTEP 22 devotes $2 billion to substation work, $1.4 billion to line upgrades, $440 million to new lines, $146 million to voltage devices and $109 million to transformer projects.
The developers behind the Grain Belt Express asked that MISO incorporate its line and other “advanced stage merchant transmission” into annual transmission planning assumptions. (See Invenergy Announces Grain Belt Express Expansion.)
Boegeman reiterated MISO’s stance that it doesn’t include merchant transmission projects in modeling until the projects execute interconnection agreements with MISO or until they have been included in a relevant integrated resource plan.
A group of New England suppliers is raising worries about the costs of the cost-of-service agreement between ISO-NE and the Mystic Generating Station heading into what many believe could be the priciest winter for gas in recent memory.
In a letter to ISO-NE officials dated Sept. 29, the group of load-serving entities pointed to the high costs of the agreement for its first few months of existence this summer: $13 million for June and $48 million for July. Heading into this winter, they warn, the “costs could balloon to levels not contemplated in 2018,” when the agreement was put into place.
The suppliers said they don’t take issue with the need for the agreement, which is staving off the retirement of Mystic, a critical gas-fired plant in Massachusetts, until 2024. But they do want to try to protect themselves and consumers from the costs of the program.
“We have grave concerns regarding the winter months, when gas prices will be at their highest, and the costs that we could face under the agreement,” the companies wrote. “No one in 2018 could have predicted how much more volatile and unmanageable hedging these costs would become considering world events.”
To try to manage the risk, the companies asked ISO-NE to provide more information and transparency about the agreement, including a cost estimate for the whole agreement and a cost estimation worksheet for its first months.
“The LSE group recognizes the challenges ISO-NE has faced that led to the Mystic COS agreement and the hard work that ISO-NE is doing to prepare for this winter,” they wrote. “The primary goal here is not to thwart those efforts but instead to work together to mitigate the costs associated with the Mystic COS agreement as much as possible.”
The companies are Brookfield Renewable Trading and Marketing, ENGIE Energy Marketing, NextEra Energy Marketing, Shell, Vistra and Vitol.
At the NEPOOL Participants Committee meeting on Thursday, ISO-NE COO Vamsi Chadalavada promised that the grid operator will work with them.
“ISO understands and appreciates the gravity of the situation,” he said.
Chadalavada said ISO-NE experts will present on the administration of the contract at the Markets Committee this week. He also said the grid operator is planning to do a scenario analysis to help inform cost estimates for the winter months. And he said the RTO is reaching out to LSEs, states, consumer advocates and transmission owners to talk about possible changes to cost allocation for the second year of the agreement.
Other PC Action
It was a busy day for the PC, which also saw a number of significant votes and presentations.
Chadalavada presented the latest iteration of the RTO’s 2023 work plan, which includes intensifying focus on the development of a day-ahead ancillary services market and resource capacity accreditation. Both will be regular topics of NEPOOL meetings in the coming months, and the grid operator is planning to file to FERC on both by the end of 2023.
Work on energy adequacy, including considering changes to the Inventoried Energy Program, is another highlight.
The committee also approved ISO-NE’s proposed installed capacity requirement values for Forward Capacity Auction 17, despite longstanding stakeholder frustration over the methodology for calculating ICR and the assumptions about imports from New York.
The systemwide demand curve for the 2026/2027 capacity commitment period | ISO-NE
The approved ICR for the 2026-2027 capacity period is 31,306 MW, and the net ICR is 30,305 MW.
The PC also signed off on the 2023 budgets for ISO-NE and New England State Committee on Electricity.
SPP has posted a Markets+ draft service offering that lays out the RTO’s proposal to “modernize and enhance” operation of the Western grid.
The document provides the proposed governance structure, market design and other key features of Markets+. SPP describes the service offering as providing Western Interconnection utilities that aren’t ready to pursue full RTO membership a voluntary, incremental opportunity to realize significant benefits.
The governance and design principles are based on feedback SPP has received from the Western utilities with which it hopes to partner. Participants have until Oct. 28 to provide additional input to the service offering.
The grid operator said the design sessions have narrowed the day-ahead market’s basic structure to two possible implementations: a voluntary, financial market with financially binding day-ahead positions that include physical instructions for resources to start and stop, and a multistage process where a reliability-based, physical resource commitment occurs followed by a purely financial and voluntary day-ahead market.
SPP will host a Markets+ development update webinar Nov. 1 to discuss funding the tariff development for the offering and commitment agreements. An in-person meeting of the Markets+ development group will be held Nov. 15-16 in Westminster, Colo., before the final service offering is released.
RTO staff and Western utilities will continue their work in two phases. First, potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents. The second phase will begin with FERC approval.
SPP said it will take 21 months to develop and prepare the FERC package at a fixed cost of $9.7 million. It said staff will work with stakeholders to develop a cost allocation approach for the startup costs before the final service offering is issued. Potential participants will pay a monthly rate of $500,000 to support the responses, technical analysis and research necessary to gain final FERC approval.
Eleven Western entities have already told SPP they are committed to working with the grid operator to build a Western market that includes “both a workable governance framework and a robust market design.” (See SPP’s Markets+ Offering Attracts 6 More Western Entities.)
Staff Drafting JTIQ Policy
SPP staff told stakeholders they are drafting the governing language to allocate costs for any projects identified in their joint targeted interconnection queue study with MISO. The grid operators plan to assign 90% of the $1 billion study’s portfolio to interconnection customers and the remaining 10% to an aggregate of their load, but they were met with some pushback during a Sept. 30 joint stakeholder meeting. (See Stakeholders Not Sold on JITQ Projects’ Cost-Sharing Plan.)
“We’re trying to solidify the principles to where we can build governing language around them and then move it into the regulatory arena,” SPP’s Neil Robertson, coordinator of system planning, told the Seams Advisory Group Friday.
Staff said they plan to post a policy paper this week designed to gain approval for the cost allocation mechanics and methodology that the SPP region will use. They have scheduled meetings with state and federal regulators to secure their buy-in and hope to get approval from the Regional State Committee in January. The goal is to make the necessary changes to the joint operating agreement and file with FERC in the first quarter.
Air Products (NYSE:APD) plans to spend about $500 million to build a plant in northern New York that would produce 35 metric tons of liquid hydrogen a day for use as vehicle fuel, the company announced Thursday.
The Allentown, Pa.-based industrial gas supplier is siting the facility in Massena, near the New York Power Authority’s St. Lawrence-FDR hydroelectric plant. NYPA has already allocated some of its low-cost power to the proposed green hydrogen plant, which would go online in 2026 or 2027.
Air Products said in a news release that the project budget will rely on incentives from state and local governments and the recently passed federal Inflation Reduction Act.
Liquid hydrogen distribution and dispensing operations are planned beside the production facility. Air Products is also considering construction of a network of hydrogen vehicle fueling stations across the Northeast, in part to fuel its own trucks: The company has committed to converting its roughly 2,000-truck global fleet to zero-emissions vehicles powered by hydrogen fuel cells.
“This project is another demonstration of our leadership role in the low-carbon hydrogen and the hydrogen for mobility markets, and New York state’s and IRA incentives will continue to encourage hydrogen’s key role and our investment in the energy transition,” Air Products CEO Seifi Ghasemi said in the news release.
The company said it expects demand for green hydrogen in the Northeast to grow dramatically with New York’s adoption of the federal Advanced Clean Trucks rule and New York’s leadership of a multistate effort to become a designated hub through the federal Regional Clean Hydrogen Hubs program.
The New York State Energy Development Authority has requested another year to set up the system of renewable energy credits that is part of the state’s plan to bring clean energy into New York City.
The Public Service Commission had set an Oct. 11 deadline for the implementation plan for the Tier 4 program of the Clean Energy Standard. But in an Oct. 7 letter to the PSC, NYSERDA said Tier 4 is a complex and all-new aspect of the state’s clean-energy strategy, with many requirements and many involved parties.
Because energy delivery from the two Tier 4 contracts is not expected until 2026 and 2027, NYSERDA wrote, there is time for a longer, more thoughtful process. It asked PSC to push the deadline back to Oct. 11, 2023.
Tier 4 was designed to increase use of renewable energy in New York City; while the generation mix in most of the state leans heavily toward clean power, the city itself relies almost entirely on fossil fuel-generated electricity.
The two approved Tier 4 projects — Clean Path New York and Champlain Hudson Power Express — are HVDC transmission lines that would deliver thousands of megawatts of solar, wind and hydro power to the city from Canada and upstate New York. (See NYPSC OKs 2 Huge Clean Energy Projects for New York City.)
Two environmental advocacy groups told RTO Insider on Friday that a one-year delay would not be a setback in the state’s clean energy transition.
Conor Bambrick, director of climate policy at Environmental Advocates of New York, noted that Champlain Hudson itself had pushed its target completion date back from 2025 to 2026 because of supply chain constraints and delays in the regulatory process.
Anne Reynolds, executive director of Alliance for Clean Energy New York, said the extension NYSERDA is seeking does not entail the projects themselves.
“NYSERDA apparently needs more time to iron out some complex issues with how the contracts will be managed and how the renewable energy credits from the projects will be bought and then sold, but this delay will not affect the two Tier 4 projects contracted to deliver clean power to New York City,” she said via email. “This administrative delay shouldn’t affect the project schedule, and the operation date for the projects is still three to five years out.”
In its request for an extension, NYSERDA said development of the implementation plan depends on resolution of issues beyond its direct control. It said its staff are meeting regularly with external consultants, NYISO working groups and Tier 4 sellers’ teams to develop the implementation plan.
