ISO-NE on Feb. 6 presented the NEPOOL Markets Committee with the initial results of the RTO’s Resource Capacity Accreditation (RCA) impact analysis modeling, providing a preliminary look at how the changes will affect the accreditation values and capacity market revenues of different resource classes.
The initial results showed that the accredited capacity value of the entire resource mix decreased by about 17%. The resource classes generally boosted by the RCA updates include wind, energy efficiency and hydro. Accreditation values also increased slightly for dual-fuel gas and oil resources, as well as for a broad category of nonintermittent resources including nuclear, coal, wood, municipal solid waste and landfill gas.
In contrast, the RCA changes would significantly decrease the accredited capacity of oil-only, battery storage, active demand response and solar resources. Gas-only resources would also take a modest hit.
ISO-NE’s Dane Schiro noted that the resource class impacts are aggregations. He highlighted some of the main factors that could impact an individual resource’s accredited capacity.
For thermal resources, having a high rate of historical forced outages was generally a significant factor in the loss of accreditation. Resource size also plays a role: Smaller thermal resources typically have higher accreditation values, because a forced outage of a smaller resource is less likely to cause shortfalls.
The accredited capacity of storage resources depends largely on duration, Schiro said. For intermittent resources like solar and wind, higher accreditation values will go to resources that typically produce energy during the times it is most needed.
As the resource mix and the timing of reliability concerns continue to shift, the capacity values and revenues for different resource classes will also shift. While ISO-NE assessed that about 80% of the loss-of-load risk occurs in the summer, the shift in risk toward winter will likely increase the annual accreditation values of resources that perform better in that season.
In March, ISO-NE is planning to present to the MC the results of modeling sensitivities related to the resource mix and load profile and will detail how these factors affect accreditation values.
Nonfirm Gas Modeling Concerns
Pallas LeeVanSchaick of Potomac Economics, ISO-NE’s External Market Monitor, outlined for the MC some concerns about the RTO’s proposed approach to accrediting non-firm gas capacity.
ISO-NE said at the previous MC meeting that a “market constraint approach” that would limit the total amount of capacity available to gas resources would be its preferred method, but it said this method “is not implementable” for Forward Capacity Auction 19. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.)
LeeVanSchaick said ISO-NE’s proposed interim “derating approach” will likely overaccredit nonfirm gas resources, reducing the incentives for firm fuel contracts that would increase winter reliability.
He proposed that ISO-NE should instead “estimate the marginal reliability impact (rMRI) of nonfirm gas-fired units in the same manner as other resource types,” and accredit capacity using an rMRI floor “that would be sufficiently high to ensure available nonfirm gas is fully utilized in periods of reliability risk.”
The Massachusetts Attorney General’s Office expressed concerns in a January letter to the RTO that its proposal would overaccredit nonfirm gas resources while showing interest in expediting work on a market constraint approach.
“The opportunity to bypass ISO’s transitional derating approach would be a substantial benefit to the development of a seasonal capacity market proposal for FCA 19,” the AGO wrote.
The state regulatory organizations for both MISO and PJM have sent a letter to the RTOs asking them to redouble efforts around interregional transmission planning.
The Organization of MISO States (OMS) and the Organization of PJM States, Inc. (OPSI) penned a joint letter to MISO and PJM, telling them the time is right to initiate long-term interregional transmission planning. The letter was signed by the presidents of OMS and OPSI and addressed to the RTOs’ Interregional Planning Stakeholder Advisory Committee. MISO South state agencies didn’t participate in the letter.
“The transition from dispatchable thermal generators to intermittent, clean energy resources, and a surge in electric demand raise challenges to PJM, MISO and their interconnected neighbors’ ability to reliably and cost-effectively support one another when called upon,” OMS and OPSI wrote.
The organizations said their concerns are heightened by increasingly common severe weather. They said MISO and PJM were “heavily dependent” on one another’s resources while importing and exporting to other neighboring regions during the December 2022 arctic blast. They also said last August’s heatwave forced MISO to import roughly 8.5 GW from PJM and Manitoba.
“While these events were managed, the growing frequency of these events and shrinking capacity reserves in each footprint [have] the potential to disrupt electricity supplies, which in turn disrupts the economy and may put public health and safety at risk. Expanding transfer capacity between regions can help to improve grid resilience and minimize the negative impacts of extreme weather events,”
OMS and OPSI pointed to the U.S. Department of Energy’s recent National Transmission Needs study, FERC considering a rule to establish a minimum transfer capability between regions and Congress tasking NERC with studying interregional transmission capacity.
“With these factors in mind, OPSI and the OMS urge PJM and MISO to begin to explore joint long-term interregional transmission planning between their footprints while maintaining a focus on affordability and identifying optimal solutions,” the organizations wrote.
The two said MISO and PJM should jointly model their systems, work with state regulators to agree on reliability and policy objectives, and borrow from their existing long-term planning to devise an interregional process.
“Both of our organizations have a renewed focus on interregional planning,” OMS Executive Director Marcus Hawkins said during a Feb. 7 MISO Advisory Committee teleconference.
RTOs Respond
MISO responded that it’s always looking to improve its planning processes, including interregional planning.
“MISO has a long history of performing coordinated interregional transmission planning with its neighboring grid operators. Interregional planning helps us identify projects that improve the system’s ability to mitigate constraints, respond to extreme weather and increase interregional transfer capability,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.
Morris said MISO appreciates the regulators’ input and looks forward to “enhancing our work with our neighboring transmission planning partners while balancing our staffing needs to identify and move forward the regional and interregional solutions needed to respond to the evolving resource mix.”
PJM spokesperson Jeffrey Shields said PJM already engages in healthy collaboration with its neighbors to identify congestion-relieving and reliability-boosting projects, as outlined in the MISO-PJM joint operating agreement.
In an emailed statement to RTO Insider, Shields said PJM has significant export capability, as evidenced by the 12 GW in exports PJM flowed to neighbors at the height of the mid-January arctic blast.
“At the same time, PJM is committed to working with MISO and others to determine if more should be done with interregional transmission. That discussion is ongoing,” Shields said. “PJM believes that the best way forward is with analysis on how best to define whether and what level of transmission solutions are needed to ensure sufficient interregional transfer capability. We need to understand very clearly what the problem is that we’re solving for before committing significant investments that will be borne by customers.”
Shields said while a minimum transfer capability is “sensible,” interregional planning should not become a substitute for RTOs maintaining adequate reserve margins.
“If all of our regions are hit with the same winter storm, the results could be very harmful to consumers,” he said.
The grid operators will address the regulatory organizations’ request again at the March 1 teleconference of their Interregional Planning Stakeholder Advisory Committee.
MISO and PJM have approved one large interregional market efficiency project in 2020 and four sets of smaller transmission projects aimed at relieving congestion since 2017. The two haven’t completed an interregional transmission planning study since 2022.
MISO revealed last week that its draft 2024 Transmission Expansion Plan calls for $5.5 billion in projects, with the South region again accounting for some of this year’s most expensive projects.
MISO has a $5.5 billion, 453-project portfolio in its hands thus far under MTEP 24, stakeholders learned over a series of subregional planning meetings last week. The draft MTEP 24 represents a more typical investment amount for MISO’s annual transmission cycle on the heels of the record-breaking, $9 billion MTEP 23.
However, MISO South transmission owners are continuing last year’s trend of recommending costly local projects.
MTEP 24 contains $793 million in generator interconnection projects, $904 million in baseline reliability projects needed to meet NERC criteria and almost $3.8 billion in “other” projects, or projects needed to address load growth, the age and condition of existing facilities and transmission owners’ self-imposed reliability criteria.
Draft MTEP 24 spending | MISO
MISO said the 10 most expensive projects account for 26% of the total proposed MTEP 24 costs, with seven located in MISO South.
MTEP 24’s costliest baseline reliability projects either rebuild or construct lines and substations in the South. The portfolio also includes projects to meet load growth in central Mississippi. The central part of the state is positioned for even more load growth, with Entergy announcing it will power two data centers totaling $10 billion for Amazon Web Services, Amazon’s cloud technology subsidiary.
“Again, we have a big year in the South,” Trevor Armstrong, manager of MISO South’s expansion planning, said during a Feb. 8 South Subregional Planning meeting.
Armstrong said most of the generator interconnection upgrades in the South region are intended to connect new solar farms.
Amanda Schiro, MISO senior manager of expansion planning, attributed some of the continued uptick in MISO South projects to load growth while working around the South’s webbing of load pockets.
Schiro said MISO will select some projects for project alternatives study, though it hasn’t decided which projects warrant further analysis. She said MISO will keep stakeholders informed on which projects are getting a second look.
“We are looking for more efficient solutions, potentially larger solutions to replace some local projects,” Schiro said during a Feb. 5 Central Subregional Planning meeting.
However, at a Feb. 6 West Subregional Planning meeting, Expansion Planning Manager Zheng Zhou said there are “limited opportunities” to devise alternatives for some project categories, such as load growth, age and condition replacements, and smaller projects, such as breaker replacements.
Some stakeholders urged members to upgrade to advanced conductors when completing age and condition projects. They said using state-of-the-art conductors on replacement projects will save money in the long run.
MISO will continue to evaluate part of a project Entergy submitted last year to meet load growth in the Amite South load pocket in southeast Louisiana under MTEP 24. MISO made a substitution on the first section of Energy Louisiana’s nearly $2 billion, three-part Amite South reliability project during MTEP 23 and delayed approval of the third portion of the project until it can vet project substitutes. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)
So far, MISO hasn’t landed on a satisfactory alternative to part three of Amite South project, but it’s still searching.
“At this point, we’re performing longer-term studies to see how it fits in with the phase one and two portions of the project,” Armstrong said.
Schiro said last year’s MTEP represented the largest investment in the South region since its integration 11 years ago. She also said MTEP 23 saw a record-breaking number of generator interconnection queue applications.
Over 2023, MISO developers struck generator interconnection agreements for 69 projects and withdrew 145 projects.
More withdrawals are all but certain. For the 2021 cycle of generation projects wishing to connect in MISO South, MISO’s studies show $14.5 billion in network upgrade costs is needed. MISO said South region generation projects currently face around $100 million apiece in interconnection costs.
MISO’s current generator interconnection queue consists of 1,379 projects totaling 237.1 GW. Those figures don’t yet include the 2023 class of project submittals. MISO has put those entries on hold until March while it implements new, stricter queue rules meant to discourage speculative generation projects. (See MISO to Try Again for Interconnection Queue MW Cap, Open Window for 2023 Requests.)
President Joe Biden on Friday removed “acting” before FERC Chair Willie Phillips’ title, as Commissioner Allison Clements announced she would not seek a second term.
Phillips had been serving as “acting” chair since the start of 2023 after Sen. Joe Manchin (D-W.Va.) refused to hold hearings for the renomination of former Chair Richard Glick, who had to step down at the end of 2022.
“I’m honored to continue to lead FERC as chairman and thank [the president] for his faith in my leadership,” Phillips posted on X. “I’m laser focused on securing a reliable, affordable and sustainable energy future for our nation.”
The “acting” title did not functionally change Phillips’ job at the commission; it signaled that the White House had intended to replace him with a new commissioner. (See Phillips Addresses Acting Status as FERC Awaits Nominees.)
The announcement came the same day that POLITICO reported that Clements would not seek another term, which her office confirmed to RTO Insider. But it would not comment on what she intended to do after her term expires June 30; commissioners whose terms have expired without a replacement can stay at their posts until Congress adjourns at the end of the year.
The opening means the White House and Senate will have up to three new nominees to process. Glick’s seat has been open since his departure, and former Commissioner James Danly’s has been since the end of last year, as he also stayed past his own June 30 term expiration. (See Secretary Bose and Commissioner Danly Honored at Their Final FERC Meeting.)
Failing to move any nominees before Clements departs would leave FERC short of a quorum and unable to vote out orders, which happened early in former President Donald Trump’s term.
Before joining FERC in late 2021, Phillips was chair of the D.C. Public Service Commission. He previously worked as assistant general counsel at NERC. He earned his law degree from Howard University School of Law and his bachelor’s from the University of Montevallo.
Clements came to FERC in December 2020 after a range of experience in energy law in both the public and private sectors with stints at Energy Foundation, Good Grid and the Natural Resources Defense Council. She earned her law degree from the George Washington University Law School and her bachelor’s from the University of Michigan.
The news about Phillips’ title was applauded by many, with Manchin, the Senate Energy and Natural Resources Committee chair, saying he looked forward to working with him on an “all-of-the-above energy policy.”
“Throughout the last year overseeing a very productive and bipartisan FERC, Chairman Willie Phillips has proven time and time again that he was the right person to lead this ever-important agency from the start,” Manchin said. “Amid the ongoing need to bolster our energy infrastructure, I have no doubt that Chairman Phillips will continue to lead FERC with his wealth of experience and consensus-building skills to the benefit of our country.”
Advanced Energy United Managing Director Caitlin Marquis also welcomed the news, noting it will allow Phillips to continue working on key issues like transmission planning.
“As FERC continues work on these issues and takes up additional priorities, Advanced Energy United asks that the Biden administration quickly nominate new commissioners eager to tackle the challenges and opportunities facing the electricity system, ensuring that FERC is wholly staffed and equipped to take on critical energy sector issues,” Marquis said.
In a newly published white paper, NERC warned that remaining industry “knowledge gaps” around electric vehicles and their charging systems may make it difficult for grid operators to maintain reliability.
The Potential Bulk Power System Impact of Electric Vehicle Chargers report, released Feb. 8, examines the effect that the adoption of EVs — specifically, the widespread installation of EV chargers at homes and businesses — might have on the reliability of the North American electric grid.
NERC has studied the topic before, releasing a report last April with WECC and the California Mobility Center on the performance of EV chargers during grid disturbances. (See NERC, WECC Outline EV Charging Reliability Impacts.) The new white paper was intended to build on this study, as well as a similar report by Pacific Northwest National Laboratory released in 2021.
Citing a 2022 projection from online EV marketplace Recurrent Auto, NERC noted that EVs are now expected to account for more than half of new vehicle sales in the U.S. by 2030. This is more than double the expectation when Recurrent first performed the projection in 2018 and is based on market factors such as growth in consumer demand and supply chain improvements.
An EV owner is necessarily also an EV charger, and grid planners will need to account for the load created by all these new sources of demand for electricity. This challenge comprises the main focus of NERC’s white paper.
The ERO noted that “larger EV charging loads are anticipated to use higher charging levels that necessitate direct connection to the BPS to supply a large EV charging load.” At the same time, the mobile nature of EVs means they could conceivably charge at any location, whether they have the specialized equipment for faster charging or not. This adds an element of uncertainty to load forecasting.
In addition, NERC pointed out that EV charging can be “grid-friendly” or grid-unfriendly depending on the approach used. Grid-friendly charging supports the stable operation of the grid by reducing voltage when grid voltage drops, while unfriendly charging increases voltage during such times, putting more strain on the grid. An overabundance of grid-unfriendly charging stations could have a negative effect on reliability.
The white paper includes the results of a study performed by NERC to evaluate the potential effect of EVs on reliability. In the study, a single base connection represented the Western Interconnection, with the team altering elements of the scenario to simulate large-scale EV adoption. Four cases were developed: a long-term horizon under heavy summer conditions with and without high EV adoption, and near-term horizon under light spring conditions with and without high EV adoption.
The study team found that EV chargers did exhibit some troubling behavior in their simulations. For example, some chargers appeared to exhibit a delay in sensing system faults and performing ride-through behavior or changing their tripping modes, which could slow system recovery. The team also noticed delays in returning to pre-disturbance consumption, which might also complicate operators’ visibility into the state of the system.
NERC recommended that manufacturers of EVs and charging systems improve their collaboration with electric utilities and “establish performance criteria and standards regarding grid-friendly EV charging methods.” The ERO said that if such collaboration proves difficult, policy makers may need to intervene.
The white paper also recommended that transmission planners incorporate charger performance into their planning criteria to indicate the performance types that are grid-friendly for their area. NERC suggested manufacturers could “address these criteria with EV charging software updates.”
ISO-NE told the NEPOOL Markets Committee on Feb. 7 that it is proposing a major redesign to its capacity market, moving from a three-years-ahead schedule to a prompt and seasonal design.
To accommodate the change, the RTO is also proposing an additional two-year delay of Forward Capacity Auction 19 for the 2028/29 capacity commitment period (CCP).
FCAs are currently held more than three years prior to each CCP. ISO-NE is proposing to break up the CCP into distinct seasons and hold the capacity auction just several months before its start.
ISO-NE has been contemplating the move with NEPOOL stakeholders for several months and commissioned Analysis Group to study the proposed changes. The consulting firm recommended that the RTO make the move, writing that it would “support the transition toward a grid of the future.” (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)
To provide time to complete the changes, ISO-NE is also proposing a “backstop” two-year delay of FCA 19 if the redesign is not approved by the time it is to be held in February 2026. FERC had approved a one-year delay of the auction to allow the RTO to implement its resource capacity accreditation (RCA) changes and contemplate the move to a prompt and seasonal market. (See FERC Approves ISO-NE’s One-Year Delay of FCA 19.)
ISO-NE expects the MC to vote on the delay of FCA 19 in March. The RTO did not comment on when it would put the redesign before stakeholders.
Chris Geissler of ISO-NE said the changes would better prepare the region for the changing resource mix and demand profile. A prompt market would better reflect “demand and resource capabilities used to determine capacity awards, thereby producing more cost-effective outcomes,” he said.
While New England’s grid reliability risks have historically been concentrated in the summer, ISO-NE anticipates that winter will surpass it in the coming years with the increase in heating and transportation electrification. Geissler said a seasonal market would help the region prepare for this shift because it “more accurately accounts for seasonal differences in resources’ supply capabilities and forecast energy demand.”
Geissler also highlighted some design components that have yet to be determined. These include when exactly the prompt auction would be held, the number and length of the seasons, and whether seasonal auctions would be held separately or all at the same time.
A prompt and seasonal market would also mean significant changes to the resource retirement process, which is currently connected to the FCM, Geissler said. While ISO-NE could decouple the retirement process from the capacity market to maintain the current retirement notice timeline, a shorter timeline could provide some benefits, he said.
“ISO plans to prioritize evaluating retirement process reforms, including tradeoffs between shorter and longer time frames, and to discuss its recommendations with stakeholders early in the prompt/seasonal design discussions,” Geissler said.
Geissler noted that the proposal “includes language allowing resources with early in-service dates to submit qualification materials in 2025 and 2026” to allow them to quantify for earlier reconfiguration auctions.
In a public letter to ISO-NE issued in mid-January, Jamie Donovan, an analyst in the Energy and Environment Bureau of the Massachusetts Attorney General’s Office, expressed support for a seasonal market but said the AGO is “still weighing the tradeoffs of a prompt market.”
Donovan added that the AGO is concerned “that the expanding scope of capacity reforms could increase project implementation risk and [about] the difficult situation that could arise if FCA 19 is further delayed for the development of a prompt/seasonal market design that is not completed in time or rejected by FERC.”
Once stakeholders have voted on the additional delay, “we encourage the ISO to release as much of its impending market design as quickly as possible for stakeholder review and feedback,” Donovan said.
Alex Lawton of Advanced Energy United said the organization is “concerned that this change is moving forward without sufficient stakeholder discussion.”
“There are several important concerns that will not be addressed until after stakeholders are asked to vote on the issue,” Lawton said. He added that the organization would like to see more analysis on how the transition would impact price formation and “whether a prompt market can adequately incentivize new resource entry without the three-year forward price lock under the status quo.”
Slower anticipated growth in California’s population has prompted state regulators to downwardly revise the electricity demand forecast used for grid planning.
The reduced demand relative to a 2022 forecast is projected to continue to about 2033. But after that, the latest forecast shows a surge in demand compared to previous predictions, as the state’s potential new requirements for zero-emission appliances are expected to kick in.
The forecast is part of the California Energy Commission’s 2023 Integrated Energy Policy Report (IEPR). The proposed final IEPR will go to the commission for approval Feb. 14.
The CEC calls its California energy demand forecast “foundational” to state energy planning. The California Public Utilities Commission uses the forecast in overseeing energy procurement, while CAISO uses it in transmission planning.
Like previous forecasts, the CEC’s new projections show a steep growth in statewide electricity demand due to California’s rapid shift toward electrification of transportation and buildings.
Climate change is also expected to increase load, as heat waves are projected to become longer, hotter and more frequent, CEC said.
From the 2018 forecast to the 2022 forecast, the expected peak demand in 2030 increased by more than 5 GW.
Population Trends
In contrast, the latest forecast has revised energy demand downward compared with previous predictions — at least through about 2033.
The change is based on a statewide population growth of 0.2% a year, which is less than the previous projections of 0.4% annual growth. The slower expected population growth follows a state population decrease of about 0.5% in 2022. The population data come from the California Department of Finance.
“The slowdown in population growth can be attributed to slow in-migration and steady out-migration on top of an aging baby boomer population and declining fertility,” the report said.
Other factors that contributed to a lower load forecast are anticipated electric rates that are higher than previously predicted, and projections of greater growth in rooftop solar generation.
But after 2033, projected load starts to rise above previously predicted levels. That’s partly due to the expected impacts of zero-emission appliance rules that the California Air Resources Board (CARB) is considering.
Last year, CARB started holding workshops on the potential rules, which would apply to new natural gas-powered space and water heaters for residential and commercial buildings. If approved, the regulations are expected to become effective in 2030. (See California Considers Zero-emission Appliance Rules.)
2040 Peak Demand
The IEPR forecast shows CAISO peak demand growing by 1.8% a year and hitting 63,442 MW by 2040. CAISO’s record peak demand is 52,061 MW, set on Sept. 6, 2022. Peak demand in 2023 was 44,534 MW on Aug. 16, the ISO reported.
The energy forecast also includes projections for managed electricity sales, in which customer generation is deducted from consumption. The figures also factor in the projected impacts of energy efficiency, building electrification and transportation electrification.
Managed electricity sales are expected to grow from about 245,000 GWh in 2023 to 352,563 GWh in 2040. Solar generation is expected to hit 64,460 GWh by 2040.
CEC continually works to improve its energy demand modeling. For the 2023 forecast, CEC moved away from relying on historical data for its weather forecasts. The agency worked with Lumen Energy Strategy to incorporate global climate models into its projections.
CEC considers the impacts of regulations, policies and programs through an “additional achievable scenario” framework. Additional achievable load modifiers are applied for energy efficiency, transportation electrification and the fuel substitution that occurs with the shift to electric appliances.
The forecast includes estimates of the impacts from planned data centers, as well as load growth from increased cannabis consumption.
Port electrification is “partially accounted for,” CEC said. But electricity needed for hydrogen production is not included “because of the high uncertainty around the future of hydrogen,” the report said.
State legislators peppered the leader of New York’s clean energy transition with questions Feb. 7 about the sputtering progress and controversial details of the effort, but got few firm answers.
Doreen Harris, president of the New York State Energy Research and Development Authority (NYSERDA), instead emphasized what has been long and widely known: It was a very tough year for renewable energy development, in New York as elsewhere, and the state is in the midst of a reset.
NYSERDA President Doreen Harris | N.Y. State Senate
She urged that greater attention be paid to longer-term goals than to near-term targets that appear increasingly out of reach.
New York has a statutory requirement of 70% renewable energy by 2030, popularly known as 70×30; under questioning, Harris said the power portfolio stands at about 25% renewable now, much of that hydropower.
However, the pipeline of projects contracted but not constructed brings that total up to 63%, she added.
The accounting here is unclear — NYSERDA was placing its portfolio-plus-pipeline at 66% renewables a year ago, before contracts totaling 7.5 GW of renewable energy capacity were canceled.
Under additional questioning — friendly or pointed or rude, depending on the party affiliation or disposition of a given legislator — Harris appeared to concede that NYSERDA was counting canceled contracts toward the 63% total.
But a day later, her staff told NetZero Insider that in fact, 63% does reflect the subtraction of canceled contracts. The staff did not explain further but said the picture would be clearer this spring, after two rounds of new contract awards.
But the state has a way to go: The expedited onshore solicitation launched in late 2023 closed Jan. 31. Only 51 of the canceled projects were rebid. Six new bids brought the total to 57 projects with a combined 5-GW capacity.
The hope is that when the renewable energy industry returns to some semblance of pre-2023 normality, more projects with canceled contracts will be rebid.
A NYSERDA spokesperson said Feb, 8:
“As developers realign their project schedules and plans, NYSERDA is optimistic most will continue to take advantage of these competitive opportunities, helping New York’s pipeline continue to advance apace toward the 70×30 Climate Act goal and throughout the following decade.”
Public Perception
NYSERDA does not just lead the actual work of adding renewable energy capacity to New York’s grid, it works to build public support for the clean energy transition.
New Yorkers not only will be footing the enormous cost of the transition, they also will be called upon to make changes in their everyday lives to reduce their demand for power and emissions of greenhouse gases. Their buy-in is indispensable to the transition, literally and figuratively.
Wherever possible, Harris and her counterparts at other state agencies emphasize the benefits of change or the risks of the status quo in their public comments and sidestep the harder questions about the cost or even feasibility of their initiatives.
And so it was Feb. 7, when Harris and other office- or agency-level executives in the state government’s energy and environmental sectors appeared before a joint Senate-Assembly hearing about relevant portions of the budget proposed by their boss, Gov. Kathy Hochul (D).
It is an annual ritual held as the two legislative chambers prepare their own counterproposals, and it often goes beyond budget and policy line items to become a soapbox for issues dear to individual legislators and their core constituencies.
What impact it all has can be hard to determine, as legislative leaders and the governor take their three sets of proposals and hash out a final spending and policy package behind closed doors.
Republicans skeptical of the energy transition or its cost have little power to press their case, as Democrats hold both houses of the Legislature. But the Democrats are split regionally, and do not always present a unified bloc.
Much of the verbiage at the marathon hearing boiled down to the need to protect the planet and disadvantaged communities versus the high cost and uncertain means by which this will be attempted.
Environmental Conservation Commissioner Basil Seggos offered a frequent speaking point — the cost of maintaining the status quo will be greater than the cost of the transition. New York expects to sustain $55 billion in climate-related damage over the next 10 years alone, he said.
Seggos did not indicate whether New York’s energy transition would cost more or less than $55 billion, nor did he indicate what impact it would have in limiting global climate change, or when that benefit would start to manifest itself. New York totals 0.08% of the world’s land mass, is home to 0.25% of its people, and already has the smallest carbon footprint per capita or per unit of economic output of any U.S. state.
Badgered by a Republican senator on who would pay for all the multibillion-dollar clean energy projects she’s attempting to bring to reality, Harris said the cap-and-invest system the state is developing would place some of the cost on polluters rather than utility ratepayers.
She did not speculate on whether those same polluters might recoup those costs by reducing the number of New Yorkers they employ or raising the prices they charge new Yorkers for goods and services.
Looking at the huge increase in electrical use envisioned for the state — Harris said grid load might jump from 150 TWh a year now to 300 TWh by 2050 — one legislator said flatly there is no way intermittent wind and solar could meet that demand, and asked what else the state has in mind.
She avoided mention of hydrogen, nuclear and other forms of energy that are anathema to most climate activists and made only generic reference to the as-yet-unknown technologies the state hopes will be brought to market in time to make a difference, and at an affordable price.
The Next Steps
While Harris was reticent to discuss the current state of New York’s renewable energy buildout, she spoke at length on how much the state is doing to rebound.
The state’s campaign to add solar, wind and storage capacity has been slow to produce results but had generated considerable momentum by the end of 2022 — much of which dissipated amid the industry troubles of 2023.
The Open NY database shows 109 contract cancellations totaling 11.2 GW as of Jan. 30, though it does not indicate when they were canceled. Some predate the mass cancelation of contracts that followed the state’s decision in October to not give developers more money to start construction of projects that had become financially untenable. (See NY Rejects Inflation Adjustment for Renewable Projects.)
(The cancellation total is effectively about 13 GW because the database does not count as canceled two offshore wind contracts totaling 1.74 GW that will be canceled but are still in place, for now.)
Since the October decision by the Public Service Commission to not grant a price increase to existing contracts, NYSERDA has been moving (at lightning speed by the standards of the regulatory world) to counter the expected rush of cancellations. (See New York Scrambles to Maintain Momentum in Energy Transition.)
It awarded provisional contracts to 22 onshore and three offshore renewable projects totaling 6.4 GW from the 2022 solicitations. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) It still is negotiating the final contracts, more than three months later.
And it issued the expedited 2023 onshore solicitation, which drew bids for 57 projects totaling 5 GW, 51 of them rebids.
NYSERDA expects to announce provisional contract awards from the 2023 offshore solicitation later this month and from the 2023 onshore solicitation in April.
Whether New York still has a chance at meeting the 70×30 target mandated by the landmark Climate Leadership and Community Protection Act of 2019 remains to be seen.
“We’ve been talking a lot today about how we’re going to get to 2030,” Harris told the panel. “What we really need to be talking about more often is how we get to 2040 and 2050, given that this is a multidecade transition.”
A Department of Energy official defended the Biden administration’s pause on processing LNG export facilities at a Senate hearing Feb. 8.
Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.) and the committee’s Republicans told Deputy Energy Secretary David Turk the administration should reverse course and start processing applications again.
“Simply put: Politicizing LNG exports is reckless and dangerous, and it could empower and enrich Russia, Qatar and Iran,” Manchin said. “Deputy Secretary Turk, if I’m correct, DOE is just now beginning its new analysis of the economic impacts of our growing export levels. If this is the case, I strongly urge that this pause should be reversed immediately.”
Ranking Member John Barrasso (R-Wyo.) said the pause was all about the upcoming presidential election, with Biden trying to win votes from environmentalists.
“Critics have claimed that American natural gas exports would raise natural gas prices here at home,” Barrasso said. “The data shows otherwise. In the eight years since we began exporting LNG, the domestic spot price of gas is, on average, much lower than the domestic spot price on gas during the eight years before we were able to start exporting LNG.”
Turk said DOE is supposed to approve LNG export facilities to countries without free trade agreements when that is in the public interest, which is made up of economic, market, national security and environmental considerations. The last time the department reviewed how it analyzes new projects’ impacts was 2018, and much has changed since.
“First, the amount of U.S. natural gas that is being exported has dramatically increased, and we need to answer how authorizing exports beyond these unprecedented volumes could impact affordability for U.S. consumers and competitiveness of U.S. manufacturing,” Turk said in written testimony. “Second, our understanding of CO2 and methane’s effect on climate change have only become sharper, and we need to further improve our analytical tools to answer a range of questions about LNG exports’ climate and environmental consequences, both near and longer term.”
The country has 14 Bcfd of export capacity up and running now, with an additional 12 Bcf under construction and expected to be online by 2030. A total of 48 Bcfd has already been approved, which is nearly half of the total domestic production of 104.4 Bcfd.
The pause will not impact the ability to fuel allies, with Turk noting that European demand for LNG is falling, demand has peaked in Japan and South Korea will peak by the end of the decade, Turk said.
While domestic prices have not converged with the higher costs of global LNG’s yet, Turk said the Energy Information Administration has said that will happen eventually as exports grow.
The other side of the aisle of the committee defended DOE’s review, with Sen. Angus King (I-Maine), who caucuses with the Democrats, saying the department is trying to make sure the economic impact of continued growth in export capacity is worth it and to understand the lifecycle emissions of LNG exports.
“I don’t understand how you would take 50% of the production of a commodity and that won’t affect the price,” King said, referencing the total number of facilities that have already been approved.
Australia has ramped up its export capacity, and it has seen prices increase by a factor of five as it reached equilibrium with global markets.
Addressing Turk, King said, “My understanding is all you are trying to do is be sure before we add additional commitments that we know what the effect will be on a manufacturer in Michigan or a family in New England trying to heat their house.”
The analysis hopes to answer those kinds of questions, Turk said, and he expects the department will take “months, not years,” to get it done.
“If we were talking about considering a pause, this is a great, great panel for this,” Manchin said. “You have an executive order doing a pause, that’s the difference. That’s the difference I have with the administration.”
It would have made more sense to do the analysis first and then pause applications if it found additional capacity goes against the public interest, he added.
King pushed back, saying that the department is only doing its job, and it would not make any sense to keep approving projects only to find out “five years from now, it’s a complete disaster.”
“I’m just saying that the pause was ill advised from a political standpoint of sending out to the world right now that we might not be in the market,” Manchin said.
MISO’s Market Subcommittee likely will devote some time this year to discussing either a multiday gas purchase requirement or a multiday gas unit commitment process for use during extreme cold.
The RTO’s Steering Committee tasked the Market Subcommittee with consideration of the topic during a Feb. 6 teleconference. The issue was originally brought to the Steering Committee by member MidAmerican Energy.
In a written request, MidAmerican Energy’s Dennis Kimm said MISO should either introduce a multiday unit commitment process or adopt a requirement that natural gas generators buy fuel when weather is forecast that will send gas and electricity demand soaring. Kimm said the multiday commitments or natural gas procurements should not be used during normal operations.
Kimm said generators “undertake a significant economic risk in executing purchases for fuel and capacity without a guarantee that the generator will be dispatched.” He wrote that uncertainty regarding MISO dispatch “can act to discourage participation in the natural gas marketplace during times of greatest liquidity.”
MISO reported experiencing gas supply challenges, resulting in reduced generator availability, during the mid-January cold front that played out over a holiday weekend.
Kimm said some advance notice from MISO on what it plans to call up would “increase flexibility for natural gas-fired generators to obtain fuel and better situate the electric industry to adequately plan and prepare to deliver reliable service” during extreme cold.
But Executive Director of Market Operations J.T. Smith seemed unconvinced multiday commitments would improve natural gas generators’ performance issues during cold spells. He said a more successful approach would include better offers that reflect true capabilities, take into account lead times and consider temperatures and fuel procurement.
Smith said he understands generation owners want certainty, but there’s a “hesitancy from the membership” to provide true startup times and realistic availability of their generation in the market because it would harm their capacity accreditation values.
Smith said during cold snaps — including the latest widespread mid-January deep freeze — “we don’t get offers from our generators that reflect true availability.”
Smith said the optimization in MISO’s day-ahead market already gives owners and operators the signals to make commitment decisions days ahead of a weather event.
“In my mind, the multiday market already exists,” Smith said, adding he was “not so sure the problem” could be solved through MISO developing a new commitment model or fuel purchase requirement.
“Give me a valid offer of your true availability capabilities first,” he said.
Smith also said the topic likely contains resource adequacy implications that may need to be hashed out at the Resource Adequacy Subcommittee, in addition to the Market Subcommittee.
