NYISO expects it will be able to operate reliably, according to the Winter 2024 Operating Study presented to the Systems Operations Advisory Subcommittee on Oct. 9.
The ISO forecasts a 23,800 MW peak demand against 41,321 MW of total available capacity this winter, a 73.6% margin. This season’s load forecast is about 1.73% less than last winter’s expected 24,220 MW and about 7.53% lower than the all-time peak of 25,738 MW, set in January 2014.
Peak load was only 22,754 MW last winter, which was very mild. It was one of only three times during that January when load went above 22,000 MW. (See NYISO Recounts Mild Winter.)
The study notes that 935 MW of new generation have come online since last winter, spread across 13 projects. Most of these are solar farms, but they also include two wind farms over 100 MW in upstate New York and one battery facility outside of Buffalo.
Four gas turbine plants, totaling 60 MW, were modeled as deactivated since winter 2023.
COLLEGE PARK, Md. ― Maryland consumes five times more energy than it generates, has limited access to transmission in the central and eastern parts of the state and at present has only six projects totaling 1,245 MW in PJM’s interconnection queue.
“Maryland, as many of you know, has been a state where transmission has come to die,” said Jason Stanek, executive director of governmental services at PJM, in his opening remarks as moderator for a grid reliability roundtable at the Maryland Clean Energy Summit on Oct. 7.
A former chair of the Maryland Public Service Commission, Stanek provided an overview of the state’s dilemma as it seeks to cut its greenhouse gas emissions 60% below 2006 levels by 2031 and decarbonize its power grid by 2035, all while attracting new business, including megawatt-guzzling data centers.
PJM estimates data centers will grow from 4% of Maryland’s power demand in 2024 to 12% in 2029 and 16% in 2039, but Stanek cautioned those numbers could be conservative, and the RTO revises the projections every year. Since 2018, new generation coming online in Maryland has been outpaced by retirements, with 1,600 MW coming online versus 6,000 MW coming off, he said.
“Last year, Maryland held an unenviable position of needing to import [power] every single hour of every single day,” he said.
Facing each other across tables running along three sides of the meeting room, participants ranged from state lawmakers to offshore wind developers and other industry experts, each with different perspectives on the state’s challenges and possible solutions, both short and long term.
Del. Lorig Charkoudian (D) talked up a bill she hopes to introduce in Maryland’s General Assembly in January, aimed at accelerating the permitting process for energy storage and other distributed energy resources coming onto Maryland’s distribution system, outside of PJM’s jurisdiction.
“I think that PJM doesn’t do the job it needs to be doing on transmission planning, and I think that our hands are tied, and so … I have finally just given up and put [planning provisions] into this bill,” Charkoudian said.
An outline of the bill is being circulated for input from stakeholders but has been informally dubbed “Build Stuff in Maryland,” she said. “The idea is, what can we do fastest? And the thing we can do fastest is distribution utilities can put storage on the distribution grid; so, medium size … 1,2,3 MW at substations, and that can be done at a pretty quick scale to respond to some of the immediate [reliability] problems, assuming storage is treated fairly in capacity markets.”
While not on the bulk transmission system, these projects could “address our resource adequacy problems fairly quickly,” she said.
Stanek and others pointed to FERC’s recently passed Order 1920, which aims to provide a new, more comprehensive framework for RTO and ISO transmission planning, for example, calling on the grid operators to consider grid-enhancing technologies, such as advanced conductors, that can increase capacity on existing lines.
David Townley, public policy director at CTC Global, an advanced conductor manufacturer, argued that waiting for much-needed transmission to be built can take years, triggering additional risks as new generation comes online. “By the time you get the line built, you may be in a congestion point; it may not be the solution anymore,” Townley said. “Take steps you can take now to open up those capacities … because the lines are loading up and changing.”
Abe Silverman, assistant research scholar at the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University, cautioned that full implementation of 1920 is still five years away but that states now should be codifying their goals and policies for clean energy and grid planning.
“That will help a lot,” said Silverman, who previously was general counsel and executive policy counsel for the New Jersey Board of Public Utilities (BPU). “So, the more you can put on paper and hand to PJM [and] say, ‘These are our goals,’ the stronger that 1920 planning process will be.”
States like Maryland should encourage their neighbors in the PJM service territory to “codify their rules in a comparable manner.” Then they present PJM with a “comprehensive action plan” as part of the 1920 process, he said.
State of the Grid
Stanek was quizzed on PJM’s request to FERC for a rehearing of 1920, one of many the commission has received and is considering.
PJM found the 1,363-page ruling “overly restrictive for a footprint as diverse and wide, serving 65 million customers,” he said. “So, the purpose of the request for rehearing was to preserve our right to inform FERC that we think there should be more flexibility in how PJM complies” with the rule.
“Otherwise, this final rule is effectively one-size-fits-all,” Stanek said. At the same time, PJM is moving ahead to comply with the timelines set out in the rule, he said.
Stanek’s opening presentation zeroed in on the key challenges for transmission planning in Maryland.
The state’s generation mix is 42.8% natural gas and 42.9% nuclear, with coal and hydro providing about 5% each, and wind and “other” accounting for a final 4.3%.
But what’s in PJM’s interconnection queue for the state is 54% energy storage, 44% solar, 1% wind and less than 1% natural gas and hydro.
The state is one of a handful that does not have an overarching, holistic plan for infrastructure development to help guide the transition to clean energy ― as opposed to the GHG emission reduction plan the Maryland Department of the Environment issued at the end of 2023 ― Stanek said.
Further, Maryland’s offshore wind projects are not included in the state’s interconnection queue because they will be coming onshore in Delaware before connecting to the PJM grid, Stanek said.
The U.S. Bureau of Ocean Energy Management recently approved the Maryland Offshore Wind Project, which includes two separate sites totaling up to 2 GW of power. Maryland’s other major offshore wind project, Ørsted’s Skipjack 1 and 2, has been on hold since the company backed out of its offtake agreement with the state in January. The company has said it would “reposition” the project for future offtake agreements.
For PJM, Stanek said, the short-term solution for Maryland is, first, to ensure no shutdowns of existing baseload generation ― coal, natural gas or nuclear ― until the necessary transmission is in place to handle the new carbon-free generation in the queue.
The RTO intervened in the planned closure of the Brandon Shores coal-fired power plant in 2025, citing a potential for up to 600 reliability violations in Maryland, Delaware, Pennsylvania and Virginia to keep the 1,283-MW plant online via a reliability-must-run agreement with its owner, Talen Energy.
Stanek said Maryland also should accelerate permitting and siting of new generation, but cautioned getting new projects online could be complicated by Maryland’s profile as a high-risk state for utility investors in rankings from S&P Commodity Insights. In S&P’s most recent evaluation, the state was placed in the bottom of nine possible rankings, meaning it has the highest regulatory risk for investors, said Lillian Frederico, the company’s energy research director.
Frederico stressed that the rankings are not intended to evaluate whether state utility regulators are doing a good job, how they are implementing state policies or if those policies are “good, bad or indifferent.” Rather, S&P looks at regulatory decisions in rate cases and other actions, based on “the comparative level of risk for investors” and for the returns on the money they invest in utilities, she said.
Maryland’s ranking has been affected by the new commissioners on the PSC, in particular, Gov. Wes Moore’s appointment of former consumer advocate Frederick H. Hoover as commission chair. Moore (D) also named Bonnie Suchman and former state Del. Kumar P. Barve (D) to the commission.
“Just the fact that these are different people appointed by a different governor with a different political agenda, there’s some concern that there could be shifts in policy that may or may not be favorable,” she said. “When you have uncertainty, uncertainty equals risk.”
Transmission as Common Ground
While it may not be a direct result of rankings like S&P’s, Maryland has significantly fewer projects in PJM’s interconnection queue than its neighbors, including Pennsylvania (91), Virginia (107) and even West Virginia (14).
Beyond the six projects awaiting interconnection agreements, Maryland also has 35 projects totaling 1,338 MW that have agreements but have yet to be built.
Adding to investor perceptions of uncertainty, Stanek said the state has a spotty track record on permitting new transmission projects. The latest, the proposed Piedmont Reliability Project, a new 500-kV line stretching 70 miles over three counties, already is stirring the kind of local reaction ― “quick and largely fierce” ― that has stalled past projects, he said.
While not confined to Maryland, “NIMBYism is clear,” Stanek said. “Nobody wants a transmission project in their backyard.”
PJM awarded the Public Service Enterprise Group the contract for the line as part of its Regional Transmission Expansion Plan (RTEP) portfolio of projects costing about $5 billion, in a process the Maryland Office of People’s Counsel has criticized as not providing enough time for local review and input.
Charkoudian also argued that PJM’s planning process for the RTEP has not considered offshore wind development on the Atlantic Coast.
“We’re bringing massive amounts of generation onto the Eastern Shore, high-capacity offshore wind, which has the same capacity as some of the gas plants that are being defended and supported and we’re being begged to keep online,” she said. “And there’s not a planning mechanism. It is essentially … a problem for the developers or the states who want to subsidize that offshore wind to figure out how to get [it] onshore.”
Both Charkoudian and state Sen. Brian Feldman (D), chair of the Senate Education, Energy and Environment Committee, promised new initiatives on siting and permitting in the upcoming legislative session. For solar projects that have stalled out while in the PJM queue, Charkoudian’s bill could include new incentives and could push for better planning of offshore transmission so that it will “solve Maryland load issues,” she said.
Another possibility could be for Maryland to consider a state agreement approach (SAA) with PJM, similar to New Jersey’s, to provide the kind of long-term, integrated transmission planning the state needs for offshore wind, Charkoudian said.
Silverman, who was at the New Jersey BPU during the SAA negotiations, said it took four years and extensive coordination between regulators and the legislature to come up with the mix of laws and regulatory actions needed to move the initiative forward.
He again stressed the importance of regional collaboration and how the need for expanded transmission could provide common ground for states with differing policies on clean energy and grid decarbonization.
“One of the things I spend a lot of time doing is talking to states across the political spectrum,” Silverman said. “We may not agree on the benefits of offshore wind, but I think what we can agree on is, if there’s a transmission facility that reduces consumer costs in your state, you should be for it. If it’s going to improve reliability, you should be for it, and most transmission lines meet those criteria.”
The National Association of Regulatory Utility Commissioners (NARUC) in a new report laid out many of the potential use cases for advanced nuclear technology and some of the policy considerations that surround them.
Carbon capture, district heating, desalination, mining and synthetic fuel production are all possibilities, along with gigawatts of emissions-free electricity.
Numerous technical, financial and political hurdles must be cleared before any large-scale deployment of next generation nuclear reactors can occur, along with innumerable regulatory and policy deliberations.
But efforts to clear those hurdles are underway, and advanced nuclear is gaining momentum as part of federal, state and corporate energy strategies.
NARUC and the National Association of State Energy Officials offered “Energy and Industrial Use Cases for Advanced Nuclear Reactors” as an overview of the considerations and questions facing state regulators and policymakers as the new technology advances.
“This new report is a timely resource as we explore how these reactors can be utilized not only for generating electricity but also for various industrial applications,” Nick Myers, vice chair of the NARUC Subcommittee on Nuclear Issues-Waste Disposal, said in a news release.
“By providing a detailed analysis of potential use cases, the report equips state officials with the knowledge needed to support and guide the integration of advanced nuclear energy into our broader energy strategies.”
The report defines advanced nuclear as improved versions of third generation light-water reactors (dubbed Generation III+) and new designs that may be cooled by gas, liquid metal or molten salt, and may be extremely small compared with traditional commercial reactors (Generation IV).
All have an improved safety profile and a high capacity factor, NARUC writes, and depending on their design, they may also offer modular construction and configurability, tailored size, black start capability, and flexible ramping and output.
Also, Generation IV gas, metal and salt reactors would generate process heat so great as to be useful for hard-to-decarbonize industrial applications, the report notes.
Some of the other use cases, however, could entail Generation II and III reactors expanding beyond their role as central power generation for the grid.
These include:
Distributed electric generation for nearby or co-located large users: This recently has become a goal for some data center developers, but drilling and mining operations also could benefit from portable micro reactors, and the Department of Defense has interest in mobile generation in the 1 to 5 MW range.
District heating: Light water reactors, with their lower operating temperatures, could use their waste heat to warm groups of buildings up to 100 miles away. Advanced reactors could fill the same function as part of a cogeneration system. The concept is not new — the first such system went online in Bulgaria in 1988.
Desalination: Removing salt and solids from water is energy intensive. India and Kazakhstan began using nuclear power for this purpose in the 1970s.
Direct air capture: Removing carbon dioxide from the atmosphere requires heat and electricity; burning fossil fuels to generate either might tend to defeat the purpose.
High-temperature applications: Chemical and steel production require temperatures as high as 900 degrees Celsius, which is at the top end of the range high-temperature gas reactors are expected to reach.
Hydrogen: Light-water reactors can power hydrogen production through electrolysis processes. Thermochemical water splitting processes still in development would require very high temperatures that Generation IV reactors could provide.
The report concludes:
“Public utility commissions and state energy offices will play a vital role in supporting the development of advanced nuclear projects slated to begin in the next decade, so understanding potential use cases, identifying opportunities to connect the dots between larger state goals and initiatives, and considering potential challenges which might arise as advanced reactors begin construction phases will be critical in supporting these developments.”
The Bonneville Power Administration would earn $65 million in annual benefits from joining CAISO’s Extended Day-Ahead Market but face $83 million in increased yearly costs from participating in SPP’s Markets+, according to a new Brattle Group study that is sure to further inflame the ongoing debate over day-ahead markets in the West.
“We find that if most of the Pacific Northwest, including BPA, joined EDAM, customers in the region would see a cost reduction of $430 million per year,” Brattle Principal John Tsoukalis, lead author of the study, said in an Oct. 9 press release accompanying the study.
By contrast, PNW net system costs would collectively increase by $18 million under a situation in which most of the region’s entities participate in Markets+, Brattle found.
In the study, the PNW system includes BPA, Avista, PacifiCorp’s West balancing authority area, Portland General Electric (PGE), Puget Sound Energy, Seattle City Light and the numerous public utility districts that largely rely on BPA for low-cost power to serve electricity customers in mostly rural areas of Oregon and Washington.
The report is the latest in the series of Western day-ahead market studies performed by Brattle, the most recent being a white paper comparing key features of the EDAM and Markets+. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.) It was not commissioned by BPA, but rather by a group of Northwest-based EDAM proponents, including the Northwest & Intermountain Power Producers Coalition (NIPPC), NW Energy Coalition (NWEC), PNGC Power and Renewable Northwest, as well as GridLab.
Those organizations have been firmly in the camp of electricity sector stakeholders who have argued that the West must create a market with the largest possible footprint — and that pointedly includes CAISO — to allow participants to fully tap the “diversity benefit” of resources and loads that would become available from such an arrangement. The Brattle BPA study throws its weight behind that argument.
“The key benefit differentiator in customer cost savings between the two markets is the diversity of the generation resource mix available in an EDAM footprint, which includes the Pacific Northwest as well as parts of the Southwest,” Brattle said in its press release.
Study Structure
The BPA study participants included the Balancing Authority of Northern California, El Paso Electric, Idaho Power, Los Angeles Department of Water and Power, NV Energy, PGE, PacifiCorp, Public Service Company of New Mexico, Sacramento Municipal Utility District and other utilities, transmission owners and independent power producers.
Those participants “helped refine our model by performing full reviews of relevant modeling assumptions including transmission rights, transmission costs, load forecasts, fuel prices, generation mix and costs, etc.,” Brattle said, calling out PacifiCorp and PGE among the “several” reviewers that “were able to provide details relevant to BPA’s system.”
Brattle worked with the Northwest Power and Conservation Council to fine-tune its flexibility modeling of BPA’s hydroelectric system, assuming the federal power agency’s ability to dispatch its fleet would be the same across all market scenarios.
The BPA study was conducted “using a nodal production cost model of the [Western Interconnection] with added markets, transmission rights and contract-path trading functionality.” It chose 2032 as the study year “to reflect the first decade of markets operations, representing an intermediate year that captures known changes in resource mix and transmission infrastructure.”
The study models a “business as usual” (BAU) case that reflects current utility participation in markets and the known decisions on day-ahead markets (all for EDAM at this point), as well as two “market participation” cases. In the Markets+ case, BPA and almost all utilities presently uncommitted to a day-ahead market join the SPP market, while an EDAM case shows all existing Western Energy Imbalance Market (WEIM) participants either remaining in that market or joining EDAM.
The study also models two extreme weather events, each based on a historic cold snap and heat wave.
“These events are modeled as single weeks in which we increase modeled loads (peak and energy) and gas prices, including gas price volatility beyond typical weather-normalized values to reflect the increased strain on the system and the ability of markets for addressing such strain,” the study said.
The study’s transmission assumptions include a “detailed view of the physical transmission system and long-term (contractual) transmission rights”; multiple trade type options between BAAs; and “GHG unit-type-specific trading structure which closely mimics the unit-specific GHG import tracking and charge structures in the EDAM and Markets+ designs.” It also assumes participants will make all their transmission available to the market, except where study participants have called out specific carveouts.
‘Key Differentiators’
BPA’s $65 million estimated benefit from participating in EDAM came down to two key factors, Brattle said.
The first is the expectation that BPA will reduce its adjusted production costs (APC) by $43 million in the CAISO market because of increased sales revenues stemming from higher prices in EDAM during the hours when the agency usually sells power.
The second factor is a projected increase in BPA’s congestion revenue from zero in the BAU case to $166 million in EDAM, a product of “the amount of transmission BPA brings to the market, its advantageous position in the EDAM footprint, and price deltas between” California and the Pacific Northwest.
While the study found that BPA’s congestion would average about $4/MWh in both markets, the agency’s congestion revenues in EDAM would be double those of Markets+ because of its higher trading volumes in the CAISO-run market.
On the downside, Brattle found BPA’s EDAM benefits would be partially offset by a $114 million loss in bilateral trading revenues and $37 million loss (to $2 million) in short-term wheeling revenues — the outcome of declining bilateral activity.
“Bilateral trading revenue falls more in [the] EDAM [case] as almost all of BPA’s trading partners are in the EDAM,” the study found.
In the Markets+ case, BPA’s increased costs stem in part from a projected $87 million drop in bilateral trading revenues, the result of many — although not all — BPA trading partners joining the agency in the market.
But the key difference between the two cases relates to production costs. In Markets+, BPA’s APC is projected to increase by $72 million because of slightly lower prices in that market during some intervals when the agency sells its power.
“The impact on prices is mostly in overnight hours, driven by the higher opportunity for increased thermal resource dispatch efficiency during these hours in the Markets+ footprint relative to the EDAM or BAU cases, which is driven by higher gas prices in the Pacific Northwest compared to the Southwest and Rocky Mountain regions,” the study said, adding that the opportunity for that kind of dispatch efficiency isn’t available under BAU because of “trading hurdles” between the Northwest, Southwest and Rockies region.
“The increased thermal dispatch efficiency and lower prices in the Markets+ footprint benefit net buyers in the PNW through reduced purchase costs but reduces sale revenues to the detriment of net sellers in the PNW such as BPA.”
On the plus side, Markets+ would increase BPA’s congestion revenues by $88 million, while short-term wheeling revenues would remain nearly flat, at an estimated $38.9 million.
“Market congestion, bilateral trading revenues, short-term wheeling revenues, and APC savings are the key differentiators of BPA’s net benefits between EDAM and Markets+,” the study said.
PNW Findings
The Brattle finding that EDAM’s benefits for the full PNW system would far outpace those of Markets+ could be the most significant point of the study for many in the region. It could also stir the most controversy in the debate over the two markets.
The study found that the $430 million in savings in EDAM derive from a $171 million reduction in APC, “driven mainly by higher sales revenues in EDAM for the region” and $651 million in EDAM congestion revenues. Those benefits would be offset by a $283 million decline in bilateral trading revenues and a $66 million loss in short-term wheeling revenues.
The cost increase for the Northwest under the Markets+ case was largely attributed to lower sales revenues, which left the region’s APC net of revenues $18 million higher than in the BAU case.
Reached for comment, BPA spokesperson Doug Johnson said, “BPA did not participate in and has not yet reviewed the study. We will attend the Oct. 17 webinar hosted by the study’s authors and will comment on the results after we better understand the study’s methodology, inputs and findings.”
SPP spokesperson Meghan Sever said the RTO was preparing a statement on the Brattle study.
The New York Power Authority (NYPA) has compiled a 3.5-GW package of 40 potential projects as it moves into its new role as a renewable energy developer.
NYPA issued a draft of its first Renewables Strategic Plan at its Oct. 8 board of directors meeting. It lays out basic details of the 40 projects, 30 of which would be undertaken by private sector entities in partnership with NYPA, 10 by NYPA itself.
The plan also recaps changes the authority has made in the 18 months since being vested with increased responsibility in the state’s clean energy transition.
The 40 proposals entail solar and battery energy storage systems and span every corner of the state, though few would be placed in the densely populated New York City region.
The proposals are open to a 60-day public comment period, and their viability will be assessed through review of their economics, community impacts and real estate considerations before being added to the portfolio.
NYPA expects substantial attrition, however. The report did not quantify this, but a NYPA executive at the meeting said attrition is likely to be in the 80 to 85% range for early stage projects, which is in line with industry averages. More mature projects could see 30 to 60% attrition.
This was quite a letdown for advocates who had pressed long and hard for the state to take a more active role in renewable development.
The New York State Energy Research and Development Authority (NYSERDA) has extensive involvement in promoting and facilitating renewable development but does not itself undertake projects.
NYSERDA has achieved mixed results in a state where energy development has long been known to be expensive and slow. These chronic factors were joined with acute national and international financial factors that led to mass cancellations of renewable contracts in New York in the past year.
NYSERDA is attempting to pull off a turnaround but has a long way to go.
As a result, the state is on course to miss its goal of 70% renewables by 2030, possibly by a wide margin.
The Public Power NY coalition and other advocates had long sought to shift some of the emphasis in renewables away from the private sector and toward the public sector.
They succeeded during negotiations for the 2023/24 state budget, which included provisions authorizing and/or directing NYPA to develop renewables alone or in partnership, conduct workforce training for the renewables industry, set up a bill credit system for low- and middle-income utility ratepayers and shut down its fossil-burning peaker plants.
Public Power had been optimistic that NYPA could achieve results faster and at lower cost than the private sector, given NYPA’s access to low-cost capital and its independence from investors demanding return on their capital.
“NYPA has had over a year to plan for these contingencies, and should have planned to build enough capacity to account for attrition,” Public Power said in a prepared statement. “By only proposing 3.5 gigawatts, NYPA is setting the stage to fail to meet their own inadequate targets.”
The coalition said: “The Renewables Strategic Plan is an abrogation of NYPA’s responsibility to ensure that the state reaches 100% renewables by 2040, and their duty to New Yorkers to build a better future for future generations.”
‘All Hands on Deck’
Asked for comment, NYPA did not directly address the suggestion that the fate of the energy transition depends on its actions, but said it was proceeding with due diligence.
The Strategic Plan does lay out actions NYPA has undertaken in the past 18 months — created a new business unit, recruited personnel to run it, made regulatory filings, formed a subsidiary, issued a $100 million bond, and sought partners and proposals.
The document indicates the 40 projects are only the initial tranche; the plan must be updated every other year, and NYPA plans to develop as much renewable capacity as its funds allow.
This expanded role for NYPA was not supported by the energy industry. The Alliance for Clean Energy New York, for example, said it would place NYPA in unfair competition with the private sector. ACE NY pressed instead for NYPA to concentrate on developing transmission, a chokepoint in renewables development.
(NYPA, the nation’s largest state public power organization, operates more than 1,550 circuit-miles of transmission lines.)
ACE NY Executive Director Marguerite Wells said via email that the draft plan was comprehensive and could move the state closer to its clean energy goals and that partnering with private developers where possible is the right move for NYPA.
She added: “We don’t want to create scenarios where NYPA is competing with private developers on new projects, but we know there is going to be enough demand in the coming years and decades [and] we will need all hands on deck, and all ideas on how to build renewables faster are welcome.”
NYPA would not say what percentage of the 40 projects are new and how many are reboots of projects that previously held contracts issued by NYSERDA.
NYPA said project costs were not known at this early stage and estimates would not be made public. It also could not say which projects would support Renewable Energy Access and Community Help, the mechanism by which it will assist lower-income ratepayers, because that program still is in development.
The 10 self-developed projects NYPA is proposing would all be solar arrays. They would total 203.9 MW and be completed from late 2027 to late 2028.
More than 170 entities responded to NYPA’s request for information to identify parties interested in collaborating with NYPA. So far, NYPA has qualified 84 developers and investors and has negotiated with several of them.
Nine entities are listed as co-developers with NYPA on the 30 projects: Acquest Development, Boralex, ConnectGen/Repsol, CS Energy, Forward Power, NextEra Energy Resources, Oriden, Teaches Energy and YSG Solar.
In response to stakeholder criticism, NYISO has updated its draft Reliability Needs Assessment to include an executive summary and appendices, and extended the comment period on the report to Oct. 14.
“We definitely heard stakeholders’ concerns about not having enough time to review the complete report with the executive summary,” Ross Altman, senior manager of reliability planning for NYISO, told the Transmission Planning Advisory Subcommittee on Oct. 9. “So, we tried to shift the schedule up a little bit on that.”
Altman said NYISO would try to address the comments for the next version of the RNA, to be presented Oct. 21 to the Electric System Planning Working Group meeting and Oct. 24 to the Operating Committee.
“As one of the people who asked for more time, I want to say thank you for giving us a little bit more time; it’s appreciated,” said Kevin Lang of Couch White.
Stakeholders spent most of the meeting discussing the results of the RNA, which predicted that on a peak summer day with expected weather conditions (95 degrees Fahrenheit), New York City would be deficient by 17 MW for one hour in 2033, rising to 97 MW for three hours in 2034. The analysis suggests that the ISO needs to declare an official reliability need for the city’s capacity zone. (See NYISO Draft RNA Finds Reliability Need for New York City.)
The discussion focused on whether that was actually significant, or if it was a result of uncertainties in NYISO’s data and assumptions.
“So the results point to a 17-MW, one-hour deficiency 10 years from now?” asked Marc Montalvo, CEO of Daymark Energy Advisors. “Is that statistically different from zero?”
Montalvo pointed out that the given the magnitude of the system and the uncertainties, 17 MW might just be statistical “noise.” He asked Altman how to interpret that “in an actionable way.”
“Do we run out and do something, or do we say, ‘Look, this needs five more years of information before we even start to worry about it’?” he asked.
Altman said that before any solution was solicited, NYISO would re-evaluate if the need still existed based on updated information. He pointed out that there were resources in development that could come online in the next 10 years but were not far enough along to meet NYISO’s base case assumptions.
“We have an opportunity to re-evaluate next year to see if the updates would make the problem go away,” Altman said. “And then in the evaluation of solutions, we do consider which solutions are best suited for meeting this need, but we have to have a solution. … We can’t just show there’s a reliability violation and do nothing about it.”
Crypto Companies Pivoting to AI
Stakeholders also revisited NYISO’s assumption about the flexibility of cryptocurrency mining and hydrogen-producing loads.
The ISO had issued a preliminary finding of a statewide shortfall of as much as 1 GW by 2034, but it revised its assumptions about the flexibility of such large loads during peak hours, which reduced the loss-of-load expectation to below 0.1. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.)
“There is an increasing interest among cryptocurrency mining facilities to actually switch over to doing AI, which, because of their service level agreements, is much less flexible,” one stakeholder noted. “Their willingness to do one and not the other depends on, to a large extent, the price of Bitcoin or whatever other cryptocurrency they’re mining.” A data center’s stated purpose as a cryptomining operation had very little bearing on whether it would remain as one in the future, they said.
Reuters reported in August that technology companies are seeking the energy assets held by crypto miners as they race to secure electricity supply for AI and cloud data centers, estimating that about 20% of cryptocurrency could pivot to AI by the end of 2027.
“We do monitor [that], but we do recognize that we don’t know exactly how they continue to evolve,” Altman said. “Any specifics you have on that, or research you’d like to share, please email” the ISO.
NERC’s staff are working on a “postmortem” examining the development of the ERO’s recently approved reliability standard setting ride-through requirements for inverter-based resources to identify lessons for the future, the organization’s vice president of engineering and standards told its Board of Trustees.
“We’re trying to comprehensively map out a plan forward for the next year,” Soo Jin Kim told trustees at a special board meeting Oct. 8, referring to the work needed to meet the next milestone in FERC Order 901. The order, passed last year, requires NERC to submit standards to improve the reliability of IBRs in three tranches between 2024 and 2026. According to Milestone 3, the ERO must file standards addressing data-sharing and model validation for all IBRs by Nov. 4, 2025. (See NERC Submits IBR Work Plan to FERC.)
Milestone 2 covered performance requirements and post-event performance validation for registered IBRs, and the standards for this segment must be submitted to FERC by Nov. 4 of this year. Those standards were the main reason for the Oct. 8 board meeting, with trustees unanimously voting to adopt the standards:
PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers.
PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.
PRC-002-5 — Disturbance monitoring and reporting requirements.
PRC-029-1 — Frequency and voltage ride-through requirements for IBRs.
All five standards will be submitted to FERC for final approval.
Kim said NERC’s developers will look to streamline the development cycle for the upcoming milestones by examining their experience on the Milestone 2 standards — especially PRC-029-1, which met significant opposition by industry stakeholders in multiple formal ballot rounds.
The standard’s failure to achieve the required two-thirds segment weighted approval led the board to exercise for the first time its authority under Section 321 of NERC’s Rules of Procedure to streamline the stakeholder approval process. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Trustees directed the ERO’s Standards Committee to convene a technical conference to hear feedback from industry, use that input to revise the standard and post the updated standard for another ballot round.
Board Chair Ken DeFontes praised the work of NERC’s staff adapting to these directives, which required the entire process to be carried out within 45 days (though NERC did extend balloting for PRC-029-1 to give industry more time to review the changes, meaning the results came in several days after the 45-day limit).
Kim said NERC found the technical conference helpful to identify issues that kept industry from supporting previous versions. She suggested that when developing the Milestone 3 standards, the ERO will proactively call for similar gatherings to “get ahead of several of the technical issues that we see, particularly with regard to modeling.”
“We’re going to try to have, not just a technical conference, but a working session where we will have breakouts, learn from what transpired during the second milestone, and try to get to the heart of the matter with regards to certain changes that need to be applied to some of the standards,” Kim said. “We agree in concept on what needs to occur with regards to modeling, [but] there’s going to be several technical sessions.”
The board also voted to accept revisions to the charter of NERC’s Reliability and Security Technical Committee that are intended to improve the balance of industry representation at committee meetings.
Unlocking the full potential of Quebec hydropower to balance renewables through the Northeast will require major efforts to overcome barriers to transmission planning and development, speakers at a webinar led by the Acadia Center emphasized Oct. 9.
The webinar kicked off with pre-recorded remarks from U.S. Sen. Ed Markey (D-Mass.), who said “the clean energy revolution is here at our doorstep,” but “our grid is an inaccessible, one-lane road from the Model T era.”
Despite the significant up-front costs of major new transmission lines, grid modeling indicates that “in a low-carbon system in New England and Québec, building more bi-directional transmission lowers the cost of electricity,” said Emil Dimanchev, a research affiliate at the MIT Center for Energy and Environmental Policy Research.
Increased bi-directional transmission would reduce the need to curtail renewables during periods of excess generation, Dimanchev said. It also would reduce reliance on gas resources by enabling hydro to take a greater balancing role paired with intermittent renewables.
Along with cost savings, increased interregional transmission also could provide significant reliability benefits.
“Transmission gives us this ability to combine wind resources from both sides of the border, which together are much more reliable,” Dimanchev said.
Adrienne Downey, principal engineer at the floating offshore wind developer Hexicon, said offshore wind pairs particularly well with hydropower when there is enough transmission capacity to enable hydro to firm up the intermittencies of wind.
“Offshore wind is pretty much a match made in heaven with this load growth, these winter peaks … and looking at hydro and the opportunity to replenish reserves,” Downey said.
Hexicon is part of a coalition that has proposed a “shared offshore backbone transmission corridor” to connect offshore wind resources along the northern Atlantic coast, reaching shore in both New England and Nova Scotia.
The proposal likely would pay for itself through reduced power costs but remains “really a question of proactive planning,” Downey said.
Additional interregional transmission capacity also would help to even out localized weather patterns as weather-dependent renewables make up a larger portion of the generation mix, said Hannes Pfeifenberger of the Brattle Group.
About 4 GW to 7 GW of transmission capacity likely will be needed and would be “cost effective” between Canada and both New England and New York, but “the reality is there are significant barriers,” Pfeifenberger said. A lack of trust between regions, inadequate planning tools and regulatory constraints all pose challenges.
“You need everybody at the table, which is why it’s so challenging,” Pfeifenberger said. He emphasized the need to build understanding around the importance of interregional planning to lay the groundwork for agreements regarding specific transmission needs and cost allocation frameworks.
Downey said grid operators, lawmakers and officials must work to expand beyond often-ingrained habits of hyper-focusing on the local grid, while also respecting the cultural differences in how regions approach their power system.
“To bridge that, and to have these broader regional discussions, there’s some cultural sensitivities,” Downey said. “It’s important that we think about this as a social and cultural exchange with related co-benefits.”
Beyond just adding new lines, transmission planning could help identify opportunities to increase line capacity when conducting asset condition upgrades, Pfeifenberger said.
Costs associated with maintaining the aging New England grid have accelerated in recent years, putting pressure on ratepayers and causing friction between the states and transmission owners, who have proposed several infrastructure projects costing hundreds of millions of dollars. (See New England States Raise Alarm on Eversource Asset Condition Project.)
Increasing line capacity could cost more in the short term but could provide significant long-term savings, Pfeifenberger said.
“We have an existing grid that was built in the ’60s and ’70s,” Pfeifenberger said. “We can save money and reduce community impacts by better planning.”
The U.S. Energy Information Administration expects consumers will spend roughly the same on winter heating this year as they did last year, according to its Winter Fuels Outlook.
“Overall, we expect that there’s going to be, generally speaking, lower fuel prices that are going to be offset by higher consumption this winter,” EIA Administrator Joseph DeCarolis said in an Oct. 9 webinar.
The two biggest sources of space heating across the country are natural gas and electricity, at 45 and 43% of all households. On average, bills for both sources should go up slightly this winter.
The Midwest is expected to see higher bills than last year, as consumers there are expected to spend 11% more on natural gas, compared to the 1% national average, and 6% more on electricity, compared to the 2% national average. The Midwest had an exceptionally mild winter last year, so the return to more normal temperatures in the region is expected to lead to a bigger jump in demand for heating, the outlook said.
While wholesale prices have fallen this year, weather forecasts call for more cold, with EIA expecting heating degree days to tick up 5% compared to last year. But it still is expected to be a generally mild winter, with the forecast calling for heating degree days to be 2% below the average of the previous decade, DeCarolis said.
For the first time, EIA broke out the share of the average bill for each fuel that goes toward space heating. While customers spend more on electric bills overall, the space heating portion of EIA’s estimates are almost the same as those for natural gas, though the South has the biggest share of electric heating.
Temperatures can have a big effect on winter prices, though when it comes to electricity and natural gas, the effect is felt more in the wholesale markets. The impact lags on retail prices because, for the most part, they are overseen by state regulators, EIA analysts said in the webinar.
The prices for propane, which is used by 5% of households concentrated in the Midwest, and heating oil, used by 3% of total households almost entirely in the Northeast, vary more significantly with temperature because wholesale prices are more closely linked to residential prices.
“Something like a major winter storm or an acute weather event is difficult to build into our forecast because the impact on price is of something like that would be highly dependent on where the storm hits,” EIA’s Corrina Ricker said. “For example, if it were to impact production, or if it’s close to large demand centers, those types of factors would really play into how the natural gas price would be impacted.”
Winter storms can cause major price spikes, but those are short-lived, and their effect on residential prices usually is felt later when regulators allow utilities to recover costs from such events, she added.
A major trend in home heating is the adoption of heat pumps. But given how many other factors beyond the equipment can affect a home heating bill, EIA wasn’t able to tease out any differences between that technology and traditional electric heating. EIA said it was working on how to isolate the effect of different heating equipment on consumer utility bills.
“The consumption and expenditures associated with these technologies depend to a large extent on household characteristics and the climate in which they are located,” the winter outlook said. “For example, an electric resistance heater used in a small, well-insulated home in the South could result in lower expenditures than an air source heat pump placed in a larger, drafty home in the Northeast.”
That is enough to outpace the national goals of many countries but not quite enough to meet the target established at the COP28 climate summit: tripling the capacity by 2030. However, the IEA said, tripling still is possible with bold near-term action by governments.
In “Renewables 2024,” its flagship annual report released Oct. 9, IEA projects more than 5,500 GW of new capacity coming online by 2030.
Photovoltaic panels and wind turbines account for the vast majority: 80% and 15%, respectively.
Hydropower capacity growth is expected to remain stable while renewables such as bioenergy, geothermal, concentrated solar and ocean energy are expected to decline without greater policy support.
IEA attributes the growth to climate and energy security policies in nearly 140 countries that, combined with favorable economics, have made renewables cost-competitive with fossil-fired generation and fostered new demand from the private sector.
The report projects that nearly 70 countries accounting for 80% of global generation capacity are on track to reach or exceed their 2030 goals.
China is the standout among them, expected to account for 60% of the global expansion through 2030 thanks to its comprehensive support for utility-scale and distributed generation across all renewable technologies.
In all, renewables would account for nearly half of global electricity generation by 2030.
Potential stumbling blocks include high cost of capital in developing economies, weak grid infrastructure, inadequate auction visibility, unstable policy environments and curtailment of installed resources due to lagging grid investments and system integration.
Also, at least 1,650 GW of renewable capacity in advanced stages of development is waiting for grid connection worldwide; some early-stage projects are dropping out of the queue due to lack of progress.
And kinks remain in the supply chain: Record-low prices, a supply glut and manufacturing overcapacity exist for the solar industry, while the wind turbine sector is crimped by limited investment in new capacity.
Finally, beyond power generation, fossil fuel demand continues to grow in the transport, industry and buildings sectors, the report states; almost 80% of total energy demand worldwide still will be met by fossil fuels in 2030, down from 87% in 2023.
In the news release, IEA Executive Director Fatih Birol said:
“Renewables are moving faster than national governments can set targets for. This is mainly driven not just by efforts to lower emissions or boost energy security — it’s increasingly because renewables today offer the cheapest option to add new power plants in almost all countries around the world.
“This report shows that the growth of renewables, especially solar, will transform electricity systems across the globe this decade. Between now and 2030, the world is on course to add more than 5,500 gigawatts of renewable power capacity — roughly equal [to] the current power capacity of China, the [EU], India and the United States combined. By 2030, we expect renewables to be meeting half of global electricity demand.”
