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November 15, 2024

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Biden Orders Cut to Federal Building Emissions

The White House Council on Environmental Quality on Wednesday issued a federal building performance standard requiring agencies to cut energy use and electrify equipment and appliances in 30% of their building space by 2030.

The Department of Energy simultaneously proposed new standards limiting on-site emissions from new and newly renovated federal properties. Beginning in 2025, new buildings and buildings undergoing major renovations would have to limit emissions to 90% of those recorded at federal properties in 2003.

The federal government owns 300,000 buildings.

The new rules come one year after President Biden issued an executive order announcing the goal to achieve federal energy sustainability while jumpstarting clean energy industries.

The administration’s long-term target is to achieve net-zero emissions at all federal buildings by 2045, cutting carbon dioxide emissions by 1.86 million tons and methane emissions by 22,800 tons.

“Ridding pollution from our buildings and adopting clean electricity are some of the most cost-effective and future-oriented solutions we have to combat climate change,” Energy Secretary Jennifer Granholm said in a release. “For the first time ever, DOE is establishing a firm timetable to reduce the government’s carbon footprint in new and existing federal facilities — ensuring the Biden-Harris administration is leading by example in the effort to reach the nation’s ambitious climate goals.”

DOE will solicit comments on its proposal in the coming weeks and will host a webinar on Jan. 5 explaining in greater detail the scope of the rule and proposed timeline.

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ERCOT Opens Curtailment Program to Crypto Load

ERCOT has created a voluntary curtailment program for bitcoin miners and other large flexible loads that it says will reduce power use during periods of high demand, even as the cryptocurrency industry shows signs of an implosion.

The grid operator said the curtailment program is primarily intended for large flexible customers, but any large customer directly connected to a transmission service provider’s facility can participate, subject to approval by ERCOT. Registration began Tuesday and the program is expected to go live in January.

The program is temporary until ERCOT establishes a long-term set of rules of for the large loads. The grid operator created a Large Flexible Load Task Force earlier this year to develop policy recommendations to integrate the loads. The group has been considering policies related to planning, markets, operations, and large load interconnection processes and reviewing related market rules.

Woody Rickerson, ERCOT vice president of system planning, said the goal is to work with large customers to support system reliability.

“These customers are large power users but have the flexibility and willingness to reduce their energy use quickly, if needed,” Rickerson said in a press release.

Under the program, ERCOT will request curtailment of crypto mining consumption when physical responsive capability declines after non-spinning reserve service has been deployed, but before emergency response service is called on.

Program participants will not be considered market participants and are subject to the grid operator’s confirmation. ERCOT said it will not refer participants to the Public Utility Commission if they fail to comply with any curtailment request under the program.

ERCOT currently has about 1.5 GW of crypto mining load and said in August it was studying 17 GW of load from the sector. By November, 37 GW of crypto load were requesting to be interconnected. (See “Staff Studying 17 GW of Crypto Load,” ERCOT Board of Directors Briefs: Aug. 16, 2022.)

“Not all of that will be constructed, but the challenge is how much will be there in three to four years,” Jeff Billo, ERCOT director of operations planning, told the grid operator’s Board of Directors in August.

Texas Gov. Greg Abbott and former interim CEO Brad Jones have both welcomed miners with open arms, pointing to their ability to quickly shut down should ERCOT need their capacity to meet demand. Jones said earlier this year that crypto offers a “fantastic” resource and said miners are effective in balancing supply and demand.

“We need to work with these folks to bring them in,” Jones told the Gulf Coast Power Association in April. At the time, he expected ERCOT’s crypto load to reach 5 GW in two years.

“I see that as a positive, but we’ve got to think about some policy issues,” he said. (See “Jones: Will Stay as Interim CEO,” Overheard at GCPA’s 2022 Spring Conference.)

ERCOT’s flexible load task force, having agreed on some high-level concepts, has paused until January. That gives staff time to develop language for protocol changes necessary to accommodate the large loads, said Longhorn Power’s Bob Wittmeyer, the group’s vice chair.

ERCOT pays industrial users to shut down during tight conditions. The grid operator’s low wholesale energy prices have also been a draw for crypto miners, but they have been rising recently.

The bankruptcy of FTX, a $32 billion cryptocurrency exchange, has sent shivers through the industry. The financial losses, criminal investigations and skepticism in Washington, D.C. have cast further gloom.

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Manchin Presses Permitting Proposal Excluded from Defense Bill

Sen. Joe Manchin (D-W.Va.) released the revised text of his controversial permitting legislation Wednesday after congressional leaders refused to include it in a must-pass defense authorization bill.

Environmental groups and Democratic legislators celebrated news that the fiscal year 2023 National Defense Authorization Act (NDAA) would not include Manchin’s proposal, which would accelerate permitting of energy and mineral infrastructure projects.

“Thanks to the hard-fought persistence and vocal opposition of environmental justice communities all across the country, the #DirtyDeal has finally been laid to rest,” Rep. Raul Grijalva (D-Ariz.), chair of the House Natural Resources Committee, said in a statement Wednesday. “House Democrats can now close out the year having made historic progress on climate change without this ugly asterisk. Of course, we still have much more work to do to bring justice to those communities who are continuing to bear the brunt of climate change, but I’m at least glad we’re not taking a step backwards today.”

It was the second setback for Manchin, who withdrew an earlier version of the bill from a measure to fund the government in September. The legislation had angered both Republicans upset with Manchin’s vote for the Inflation Reduction Act and Democrats, who saw it as a concession to the oil and gas industry. (See Manchin Permitting Package Cut from Spending Bill.)

But Manchin, chairman of the Senate Energy and Natural Resources Committee, vowed Wednesday to offer the Building American Energy Security Act of 2022 as an amendment to the NDAA. The House is expected to consider the defense spending bill as soon as Thursday.

“Failing to pass the bipartisan, comprehensive energy permitting reform that our country desperately needs is not an acceptable option,” Manchin said. “As our energy security becomes more threatened every day, Americans are demanding Congress put politics aside and act on commonsense solutions to solve the issues facing us.”

The bill would guarantee permit approvals for the Mountain Valley Pipeline and give FERC enhanced electric transmission siting authority. Manchin said his proposal would accelerate permitting “without bypassing environmental laws or community input.”

But more than 750 environmental justice groups, environmental organizations and others urged House Speaker Nancy Pelosi (D-Calif.) and Senate Majority Leader Charles Schumer (D-N.Y.) in a letter Dec. 5 to reject the bill, saying it would “fast track fossil fuel infrastructure, restrict judicial review, and erode the National Environmental Policy Act (NEPA).”

2-Year Deadline

Manchin’s bill would set a two-year deadline for projects that require a full environmental impact statement and reviews from more than one federal agency and a one-year deadline for projects requiring an environmental assessment.

It also would reduce the time community members have to file legal challenges to 150 days. Manchin would require federal district and appeals courts to randomly assign judges for such challenges “to avoid the appearance of favoritism or bias.”

Project applicants would have the right to petition a court for an order requiring any agency that has missed a NEPA or final permit issuance deadline to make a decision within 90 days. It also would require courts to consider such petitions and other litigation of energy project permits on an expedited basis.

It would also seek to close loopholes to bypass deadlines and to reduce permitting workloads by setting page limits on environmental reviews.

The president would be required to designate 25 energy projects of “strategic national importance” for priority federal review, including projects for critical minerals, fossil fuels (including biofuel), non-fossil fuels (including storage), carbon capture, hydrogen and electric transmission.

Impact on FERC

Manchin’s bill would maintain the current FERC backstop authority over electric transmission, which gives states one year to issue, deny, or not act on a permit before the commission can issue a construction permit. It would eliminate the requirement that the Department of Energy make a finding that the project is in the national interest before FERC could act.

Eminent domain could be exercised on state land.

Manchin said the revised bill also amends cost allocation language to address concerns that FERC could otherwise consider direct jobs and property tax revenue when allocating cost of a project.

The Washington Post reported that Manchin’s refusal to schedule a confirmation hearing for FERC Chair Richard Glick, whom President Biden nominated for a second term, was undermining efforts to increase electric transmission. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

“Manchin holding up Glick’s reappointment seriously calls into question whether he even thinks the transmission provisions in the [permitting] bill are necessary or important,” Howard Crystal, legal director of the Center for Biological Diversity’s Energy Justice Program, told the Post. “Maybe the fossil fuel provisions in that bill are the things that Manchin really cares about.”

A White House spokeswoman said the administration continues “to hope our FERC nomination can move this year.”

Manchin would give FERC jurisdiction to regulate hydrogen under the Natural Gas Act, while ensuring that existing interstate hydrogen facilities would be grandfathered and permitted to continue operations. It would also clarify that FERC would not be given authority to require natural gas pipelines to be built or modified to also transport hydrogen. (See Lawyers, Industry Debate Path for Hydrogen Regulation.)

Adding the bill to the NDAA would likely require 60 votes in the Senate — an unlikely prospect with Senate Minority Leader Mitch McConnell (R-Ky.) dismissing the bill as “permitting reform in name only.”

“Potential defections by between six and eight Senate Democrats could leave a gap that outstrips GOP support, especially if Republicans view House control next year as leverage for deeper reform,” said ClearView Energy Partners.

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NJ BPU Approves Rules for Grid Solar Program

New Jersey’s Board of Public Utilities (BPU) on Wednesday approved rules for a competitive utility-scale solar incentive program designed to nearly double the amount of solar capacity installed in the state a year.

The Competitive Solar Incentive (CSI) program will require interested developers to submit projects in one of five categories, each of which will award incentives at a rate determined by a competitive process in which developers submit bids on the minimum incentive they will accept to undertake their planned project.

The five categories are: basic grid supply; grid supply on a built environment; grid supply on contaminated sites and landfills; net-metered nonresidential projects above 5 MW; and storage paired with solar.

The five-member board’s unanimous approval of the program concludes its revamp of its solar incentive program, which in the past stimulated a dramatic growth in solar capacity installation but drew criticism that it cost ratepayers too much. The new program, with its reduced incentives, have drawn criticism from solar developers that the subsidies are too small to stimulate growth, especially as supply chain issues and other problems have pushed up the price of materials. (See Solar Industry Pushes for Bigger Incentives from NJ Program.)

The BPU shaped the CSI rules after six public hearings on different aspects of the proposed rules that attracted more than 130 registrants. The BPU expects to open the first solicitation on Feb. 1, 2023.

“For many types of projects, the CSI program will provide incentives for the first time in New Jersey,” according to the BPU order outlining the program. “There has been some evidence of pent-up demand for larger-scale solar development.”

Before voting to approve the program, BPU President Joseph Fiordaliso said that the state in 2001 had just six solar installations, compared to more than 160,000 installed projects today.

“This is just another step of our unwavering support of the solar industry here in the state of New Jersey,” Fiordaliso said. “Not only are we significantly increasing the amount of solar we purchase, we also expect to see significantly lower costs to the ratepayers.”

Commissioner Bob Gordon called it “a new … and even more exciting chapter in our development of solar in this state.”

‘Record Year’

The CSI program is the second part of the state’s Solar Successor Incentive (SuSI) program, which was approved in July 2021. The first part, the Administratively Determined Incentive (ADI) program, took effect immediately and provided incentives at rates set by the BPU to residential, community solar, and net metered non-residential projects of five MW and less.

The board also approved a measure Wednesday to amend the ADI program, reallocating incentive funds to provide 100 MW of additional capacity for residential projects because the 150 MW allocated in the program will soon be exhausted.

“We’re seeing a record year as far as residential solar,” Fiordaliso said. “I attribute a lot of this to the fact that obviously, the developers are out there pushing this because it is money, but also [to] the fact that our marketing campaign alerted an awful lot of residents in the state of New Jersey that we are doing solar, and how solar can benefit them insofar as their energy bill is concerned.”

The additional incentive capacity for residential projects was moved from two other project categories in the ADI program, with 70 MW coming from a category supporting landfills, brownfields or areas of historic fill, which had attracted only one project applicant since the program was opened a year ago. The BPU pulled another 30 MW from a nonresidential project segment, in which applications to date have only consumed about 20% of the available capacity.

Capacity Goals

The development of the CSI program is part of the state’s effort to reach ambitious solar goals set out in Gov. Phil Murphy’s Energy Master Plan, and state law. They call for New Jersey to install 5.2 GW of capacity by 2025, add another 7 GW by 2030 and reach 17.2 GW by 2035. State law requires the solar generated power to account for 50% of the state’s electricity by 2030.

With 4.2 GW of capacity in place as of October, the state could reach the 2025 goal. It installed 356,882 kW of capacity in the first 10 months of the year, a figure that is 5% higher than the installed capacity for all of 2021. Still, it is far lower than the 750 MW/year of installed capacity that the BPU has set as a target.

The BPU believes that competitively awarded incentives will both protect ratepayers, by incentivizing projects at the “lowest incentive contribution,” and also help developers.

“The fixed, long-term and guaranteed nature of the incentive provides a relatively low-risk incentive structure for developers, thereby encouraging investment of private capital,” the board’s order outlining the rules states.

By structuring the program into five categories, the program will “ensure that a range of competitive solar project types are able to participate despite potentially different project cost profiles,” the order says.

Protected Land

The program will award the largest share of the capacity — 140 MW — to the basic grid supply category. Grid supply on built environment will account for 80 MW; and grid supply on contaminated sites and landfill will account for 40 MW, as will net-metered nonresidential projects above 5 MW. Solar-plus-storage projects will account for 160 MWh.

The rules also set out project siting requirements to protect farmland, natural spaces and other valued land, which apply to not only projects seeking BPU incentives under the program, but all “grid supply solar installations, as well as nonresidential net-metered solar installations with a capacity greater than 5 MW.”

“This requirement will allow the board to track such projects on a nondiscriminatory basis, while also ensuring that non-incentivized projects intending to utilize the land they have reserved do so in a timely manner and are not hoarding available space or otherwise acting in an anticompetitive manner,” the board’s order says.

The guidelines were shaped using stakeholder input provided in two public hearings on a special straw proposal on the issues. New Jersey, like other states, is facing increasing pressure on open space and farmland from solar developers seeking project sites, as well as from housing and warehouse developers, sparking concern that farmland especially may be lost. (See NJ Tries to Balance Solar Growth vs. Farmland Protection.)

The rules prohibit the siting of solar projects on several types of land, among them: land preserved by funds in the state Green Acres program, which awards funds to create parkland and natural spaces; in forest areas in the state’s pinelands area; and on prime agricultural soils and soils of statewide importance.” However, the rules allow developers to seek a waiver from the prohibition in certain circumstances.

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First West Coast Offshore Wind Auction Fetches $757M

Five lease areas off the California coast brought in a total of $757.1 million as bidding ended Wednesday, with five companies named the winners in the West Coast’s first offshore wind auction, the U.S. Bureau of Ocean Energy Management (BOEM) reported.

The winners were all subsidiaries of large multinational firms with experience in offshore wind, but no developer has yet built floating wind platforms of the immense size and number envisioned for the West Coast. The large scale, deep water, lack of port infrastructure and other risk factors kept the lease bids well below two East Coast auctions held earlier this year for areas off New York and the Carolinas, where shallower waters allow for fixed turbine platforms.

The bid prices, however, exceeded those from East Coast wind auctions held in prior years, according to a news release from the Interior Department, which oversees BOEM.

“Today’s lease sale is further proof that industry momentum — including for floating offshore wind development — is undeniable,” Interior Secretary Deb Haaland said. “A sustainable, clean energy future is within our grasp, and the Interior Department is doing everything we can to ensure that American communities nationwide benefit.”

The department called the sale a “significant milestone toward achieving President Biden’s goal of deploying 30 GW of offshore wind energy capacity by 2030 and 15 GW of floating offshore wind capacity by 2035.”

California has a mandate to provide retail customers with 100% clean energy by 2045 under 2018’s Senate Bill 100. The state’s Energy Commission has proposed offshore wind goals of 25 GW by 2045 to help fulfill that target. (See California Boosts Offshore Wind Goals.)

Of the five lease areas, three are in the Morro Bay Wind Energy Area (WEA) off the Central Coast and two are in the Humboldt Wind Energy Area off the coast of Northern California.

Winning bids reached as high as $173.8 million by California North Floating, a subsidiary of Copenhagen Infrastructure Partners (CIP), for a 69,000-acre Humboldt lease area with 1 GW of potential capacity. CIP is one of the firms building the Vineyard Wind project off the Massachusetts coast and is developing other East Coast offshore wind leases totaling 5 GW.

“California is expected to develop into a key market for floating offshore wind and the auction represented a strong investment opportunity for us,” CIP Senior Partner Torsten Smed said in a statement. “By adding the new lease area to our portfolio, and based on our large global portfolio of floating offshore projects in different stages of development, we are uniquely positioned to lead the commercialization of floating offshore wind in the U.S.”

Equinor Wind US submitted the lowest winning bid for an 80,000-acre Morro Bay parcel with 2 GW of potential capacity.

“Today’s announcement confirms Equinor’s floating [turbine] leadership and strong commitment to deliver renewable energy to the U.S. It adds at least another potential 2 GW to our existing 3.3 GW U.S. offshore wind portfolio,” said Pål Eitrheim, executive vice president of renewables at Equinor. “We were among the first movers into U.S. offshore wind and are now one of the first movers into California, a market we believe will become a strategic floating market globally.”

About two-thirds of offshore wind potential in the U.S. lies in deep waters; the Pacific Coast’s narrower continental shelf drops quickly to 3,000 feet or more, requiring floating platforms, the firm noted.

Other bids were $145 million by Invenergy California Offshore for an 80,000-acre Morro Bay lease area; $150.3 million by Central California Offshore Wind, an Ørsted affiliate, for a similarly sized lease in the Morro Bay WEA; and $157.7 million by RWE Offshore Wind Holdings for the second Humboldt lease of 63,338 acres.  

The average price paid for all five parcels, totaling 373,268 acres, with up to 4.6 GW of capacity, was $2,028/acre.

That was far below the record bids in February for the New York Bight auction, which pulled in $8,837/acre for a total of $4.7 billion. It was about a third less than the $2,900/acre that bidders paid in May in a North Carolina auction that fetched a total $315 million. However, it was double the $1,083/acre paid for wind leases off the Massachusetts coast in 2018.

The provisional winners of the California auction now have the exclusive right to propose projects and seek federal approval.

Reasons for Caution

Analysts had warned Tuesday, as the auction began, that bidders could show more restraint than they had in New York or the Carolinas.

ClearView Energy Partners called floating offshore wind “a far more nascent and undemonstrated technology,” saying the higher risks could mean lower lease prices.

“The record number of [43] eligible companies bidding for the areas suggests a highly competitive environment that may not conclude until tomorrow or Thursday,” ClearView said in a statement previewing the auction.

“However, we are not yet convinced that final per-acre prices will exceed those reached for the WEAs leased off New Jersey and New York earlier this year,” the firm said. “While California has aggressive decarbonization targets and needs new non-solar renewable resources, it does not yet have policies specifically targeting offshore wind akin to those adopted by several East Coast states.”

The Business Network for Offshore Wind said it was “excited to see the commencement of the first West Coast and first floating offshore wind lease auction” but warned not to expect record prices.  

“The Network does not believe the California leases will fetch as high of auction fees as the New York Bight,” the trade association said in a statement. “The New York Bight had several key elements, including a very visible path to offtake, strong monetary and public support from state governments, a visibly emerging port infrastructure and supply chain, and apparent willingness to tackle transmission. …

“Today, the California market is not as strong, and adding in new technology development will likely result in a lower price,” it said. “However, California is a premier market with strong political and public support and being the first to market is very attractive, as auction prices will only rise over time.”

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ISO-NE: FERC Delay Sets Back DER Capacity Market Participation

FERC’s delayed response to ISO-NE’s Order 2222 compliance filing means that distributed energy resources won’t have a new way to participate in the grid operator’s next capacity auction.

In its compliance filing, sent to the commission in February, ISO-NE asked FERC to issue an order approving its response to Order 2222 by Nov. 1.

A month after that date, the grid operator made clear that, with no FERC approval yet arriving, it won’t be able to start approving and implementing rules that allow DECRs (distributed energy capacity resources), which ISO-NE defines as an aggregation of one or more DER aggregations, to take part in FCA 18, the capacity auction set to take place in 2024.

Unlike existing rules for demand response resources to compete in the market, the new rules are intended to allow for aggregations that include both demand response and other resources to also have a pathway to participate in the FCM.

“The November 1, 2022, effective date was necessary to ensure that the ISO would have sufficient time to implement the proposed rules for DECRs to participate in FCA 18,” ISO-NE wrote in a memo. “These efforts include developing software for qualification and auction participation for DECRs; establishing DECR qualification processes, user interfaces and forms, and data submission procedures; and creating associated training materials.”

ISO-NE said it will resume consideration of tariff updates for DERs to be included in the capacity auction as soon as it hears back from FERC on the Order 2222 compliance filing, but that it’s too late for participation in FCA 18, the process for which begins in March 2023.

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IMM: Faulty Assumption in MISO’s Seasonal Auction Design

ORLANDO, Fla. — MISO’s Independent Market Monitor said he has uncovered a faulty assumption behind the seasonal capacity requirements, months before the RTO debuts its seasonal capacity auction.

IMM David Patton told the MISO Board of Directors’ Markets Committee Tuesday that he believes that MISO’s seasonal capacity requirements are artificially inflated in shoulder seasons because it expects generators on planned outages to offer capacity.

“MISO’s [seasonal] requirements essentially assume that all units with planned outages will be selling capacity,” he said. “Since that would reduce the average availability of capacity purchased, it raises the requirement.”

Patton said he expects that some generating units on long-duration planned outages won’t sell capacity and will seek exclusions with the IMM from market power mitigation. The exemptions allow generation owners to withhold capacity or offer it at high prices.

“This will cause the shoulder seasons to be artificially tight — and may be short,” Patton said, pointing to the fall months that are typically rife with planned outages. He said if half the units with long-term outage scheduled during next fall don’t offer, MISO will be short on capacity over the season.

If the grid operator’s planning resource auction fails to procure enough capacity in the fall, Patton said, it would be a “manufactured shortage” and “artificial tightness.” He said MISO should publish revised loss-of-load expectations or find another way to “ratchet down” the requirement.

Patton said the issue is “pressing.”

“From an economic perspective, this is really big deal,” he said. “We would have to reject exclusion requests and force such units to sell to reduce the impact of this issue. Even then, prices would be artificially inflated if suppliers include expected penalty costs in their offers.”  

Patton said MISO’s seasonal capacity actions are a big undertaking, making it difficult for staff to anticipate all implications.

“Going to a seasonal market, there’s a tremendous number of changes that have to be made in a short amount of time,” he said.

Staff said they’re working with the IMM on a solution for their shoulder season requirements.  

MISO will simultaneously conduct four seasonal capacity auctions this spring, with accreditation values for thermal generation that vary by season. FERC in August approved the RTO’s request to clear four separate auctions once a year and to use an availability-based resource accreditation that relies on the riskiest hours in a season. (See FERC OKs MISO Seasonal Auction, Accreditation.)

Otherwise, Patton said MISO is making good progress on his yearly bundles of market improvement recommendations. (See MISO Simpatico with Monitor’s 2022 Market Recommendations.)

“I’m super excited for what MISO is doing,” Patton told board members.

“So clearly, there is a Santa Claus,” MISO director Mark Johnson joked.

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MISO TOs File to End Reactive Supply Compensation

MISO transmission owners have filed with FERC to eliminate all reactive power and voltage-control charges from their own and affiliated generation resources.

The TO sector said the revisions will result in a rate decrease for transmission customers. They agreed in October to make the filing and requested FERC backdate the change to Dec. 1 (ER23-523).

Under Schedule 2 of MISO’s tariff, most generation owners can apply to receive separate compensation for their reactive supply. The TOs said they no longer want any separate charges to pay for reactive service supplied within the standard power factor range of 0.95 leading to 0.95 lagging power factor.

The TOs proposed that online generation called up or manually redispatched by MISO to furnish reactive power outside of the generator’s deadband (a control system’s band of input values where the output is zero) should still be compensated. They said their proposal would put an end to generation receiving “compensation whether or not it ever actually supplies reactive power or whether or not it is located in an area where there is an actual need for additional reactive power.”

FERC has previously ruled that generators don’t have to be paid for reactive power within the standard range, the TOs said.

During an Advisory Committee meeting Wednesday, members asked whether the TOs expect resistance to the filing.

“I think there are a number of different views on the filing, so there is a possibility that it will be protested,” Stacie Hebert, a TO representative for Otter Tail Power, said.

MISO said it has not taken a position on the filing but submitted it to FERC on behalf of its TOs.

The TOs emphasized that their proposal will not affect the grid’s reliability.

“The proposed revisions eliminate the capability-based reactive power compensation via Schedule 2, and impact neither the need for or creation of reactive power nor the ongoing obligation of generators to provide reactive power,” MISO TOs said. “In other words, new generators will still be required to have the capability to provide reactive power within the deadband as a condition of obtaining interconnection and all generators will still be required to operate with that capability enabled as a condition of maintaining an interconnection.”

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ISO-NE Lays out Proposal for Measuring Gas Plants’ Winter Limitations

As ISO-NE continues to hack away at the complicated process of updating its capacity accreditation method, the grid operator is turning its attention to gas.

In a presentation to the NEPOOL Markets Committee on Tuesday, ISO-NE officials outlined principles for how they plan to upgrade accreditation of gas resources, which has been an emphasis for many stakeholders frustrated that the current process fails to take into account fuel storage limitations.

ISO-NE is planning to introduce a qualification rule that would reflect gas generators’ fuel storage capabilities and fuel contracting arrangements for the winter, said Tongxin Zheng, the RTO’s director of advanced technology solutions.

Gas resources’ qualified capacity for the winter season would be divided into firm and non-firm capacity. Non-firm capacity — that which is not backed up by on-site fuel storage or firm fuel contracts — would lead to a lower capacity rating for resources.

“Gas resources will be required to demonstrate firm fuel arrangements (e.g., LNG contracts, firm pipeline transport, proposed dual-fuel capability and on-site storage capability) in the qualification process,” Zheng said.

ISO-NE is also planning major changes to how it models resource adequacy during the winter. The grid operator is planning to use forecasts of available pipeline capacity and LNG under different scenarios to enhance its modeling.

Early Concerns from LS Power

Ben Griffiths of LS Power offered a rebuttal to ISO-NE, presenting on the company’s initial criticisms.

In particular, Griffiths said LS is “concerned that the ISO is deviating from its unit-specific approach when addressing pipeline gas availability.”

Unlike other pieces of ISO-NE’s marginal reliability impact (MRI) approach to accreditation, he said, the proposed fuel framework “relies on class-level accreditation mechanisms.”

ISO-NE’s resource capacity accreditation project “will be a failure unless it can reasonably distinguish between high-quality, gas-only resources and low-quality ones,” Griffiths said.

Among the various discrepancies between resources, he said, are that gas availability is spottier at downstream delivery points; different pipelines go to different points; and different units have gas arrangements with varying levels of “firmness.”

He noted an incident from March of this year, when multiple gas-fired generators warned the grid operator that they might be short on gas imminently. To fill the gap, several additional fast-start resources came online — including another gas plant, LS Power’s Wallingford facility.

“If some gas resources are coming offline for fuel unavailability while others can come online with no notice to replace them, then gas resources cannot be treated as one-for-one,” Griffiths said.

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California Offshore Wind Bidders Show Caution

The West Coast’s first offshore wind auction got off to a cautious start Tuesday, with bids closing the day at levels far lower than two East Coast wind auctions held earlier this year.

By the close of bidding at 5 p.m. ET, the high bids for five leases off the California coast had reached an average of $1,037/acre, a little less than the $1,083/acre paid for wind leases off the Massachusetts coast in 2018, the Interior Department’s Bureau of Ocean Energy Management reported.  

The auction will resume Wednesday morning at 10 a.m. ET, and some observers predict bidding could continue through Thursday, with prices more than doubling from Tuesday.

The California auction involves 373,267 acres in two large wind energy areas — the Humboldt Wind Energy Area off the coast of Northern California and the Morro Bay Wind Energy Area off the coast of Central California. (See BOEM Sets California Offshore Wind Auction Date.)

The California bidding totaled $387.1 million at the close of business Tuesday. By comparison, winning bids for the New York Bight area in February set a record of $8,837/acre, totaling $4.7 billion, while a North Carolina auction in May fetched $2,900/acre, for a total of $315 million.

As the auction began Tuesday morning, California Gov. Gavin Newsom hailed it as a “historic step.”

“Together with leadership from the Biden-Harris administration, we’re entering a new era of climate action and solutions that give our planet a new lease on life,” Newsom said in a news release. President Biden established a goal last year for the U.S. to deploy 30 GW of offshore wind by 2030.

California has a mandate to provide retail customers with 100% clean energy by 2045 under 2018’s Senate Bill 100. The state’s Energy Commission has proposed offshore wind goals of 25 GW by 2045 to help fulfill that target.

Environmental groups and trade associations lauded the start of the auction.  

“California will be the big winner in this first lease sale for the state’s multigigawatt floating offshore wind resource,” Adam Stern, executive director of Offshore Wind California said in a statement. The trade group declined to comment on the bidding so far.

Reasons for Caution

Analysts had warned that bidders could be cautious given the West Coast’s lack of offshore wind infrastructure, including developed ports, and the floating wind turbines required in California’s deep offshore waters.

ClearView Energy Partners called floating offshore wind “a far more nascent and undemonstrated technology,” saying the higher risks could mean lower lease prices.

“The record number of [43] eligible companies bidding for the areas suggests a highly competitive environment that may not conclude until tomorrow or Thursday,” ClearView said in a statement previewing the auction.

“However, we are not yet convinced that final per-acre prices will exceed those reached for the WEAs leased off New Jersey and New York earlier this year,” the firm said. “While California has aggressive decarbonization targets and needs new non-solar renewable resources, it does not yet have policies specifically targeting offshore wind akin to those adopted by several East Coast states.”

The Business Network for Offshore Wind said it was “excited to see the commencement of the first West Coast and first floating offshore wind lease auction” but warned not to expect record prices.  

“The Network does not believe the California leases will fetch as high of auction fees as the New York Bight but will likely eclipse what we saw in the Carolinas,” the trade association said in a statement. “The New York Bight had several key elements including a very visible path to offtake, strong monetary and public support from state governments, a visibly emerging port infrastructure and supply chain, and apparent willingness to tackle transmission. …

“Today, the California market is not as strong, and adding in new technology development will likely result in a lower price,” it said. “However, California is a premier market with strong political and public support and being the first to market is very attractive, as auction prices will only rise over time.”