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November 15, 2024

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Prelim NYISO Analysis: 1-GW Shortfall by 2034

New York will be short 1 GW of resources by 2034, driven by increased demand, large load growth and lack of natural gas, according to the preliminary results of NYISO’s biennial Reliability Needs Assessment.

“Preliminary results show criteria violations that will result in reliability needs,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee on July 25. “However, we are not defining those needs today. These are still preliminary results.”

New York City will experience a security margin baseline deficiency beginning as early as 2031, driven by the retirement of the New York Power Authority’s small gas plants. Altman said this could be expected to grow to 275 MW by 2034 because of demand growth.

“This is driven both by New York City load growth and also the assumption of the retirement of several small gas plants that NYPA is required by law to retire or replace,” Altman said.

Altman said that the final results of the RNA, to be presented in August, would identify some needs but that there would be more detail in the solicitations for next year.

Assumptions

The preliminary RNA assumes that many large generation projects will be online and contributing to the grid, including both the Empire Wind 1 and Sunrise Wind 2 offshore wind projects.

“This is a fairly small list, but we are tracking a much wider pool of projects,” said Altman. “This is a fairly conservative assumption. These are only the projects that we have high confidence on because they’ve met their milestones.”

NYISO

Approximately 6,400 MW of generation fueled by non-firm gas was modeled as unavailable. Altman said this modeling change was consistent with recently adopted changes to New York State Reliability Council rules. Dual-fuel sources with non-firm gas were modeled running on their alternate fuels.

“We wanted to highlight dual-fuel units that have non-firm gas contracts; we do not assume those out,” said Altman. “We just model what their capability is when they’re operating on their alternate fuel source.”

Additionally, roughly 2,100 MW of additional large loads were added to the system. Electrical imports from Chateauguay, Quebec, were set to 0 MW during winter months.

“We are setting those imports to zero in winter peak months consistent with our coordination with Hydro-Quebec and what we’re seeing in operations,” said Altman.

Preliminary Results

Ten years from now, NYISO estimates a loss-of-load expectation as high as 0.283.

“We need resources at that point to bring the LOLE to 0.1,” said Laura Popa, a manager of resource planning for NYISO.

NYISO

Popa walked stakeholders through alternate 2034 scenarios in which additional risk factors and potential solutions were modeled, including the inclusion of 9,000 MW of offshore wind, construction delays on the Champlain Hudson Power Express transmission project and the removal of certain large loads. Delaying the CHPE project would significantly impact the LOLE, bumping it up to 0.327 by 2034. Adding extra wind power or removing 1,900 MW of large load would bring the state below the 0.1 LOLE threshold.

Most questions from stakeholders centered on the math and assumptions of the model. Some wondered whether gas was being appropriately modeled as unavailable. Altman pointed out that New England was particularly dependent on natural gas and that it would continue to be used for heat, even if new construction was electrified.

“I don’t think anyone should take these results as ‘the sky is falling,’” Altman said. NYISO would prefer market-based solutions to the problem and believes it could identify an appropriate solution if it went through a solicitation process, he said.

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Counterflow: Hydrogen Flub

Last November, I wrote about the insanity of green hydrogen electricity. And I’ll return to that below.

But I’d like to start with green hydrogen generally, focusing on the first of DOE’s funded “hydrogen hubs” located in — where else? California!

From the PR materials, we can piece together a somber tale. Let’s start.

When is a Hub not a Hub?

Steve Huntoon

The term “hub” is a misnomer. There will be 10 or more hydrogen production sites (at renewable energy facilities), with hydrogen transported to four ports, 60 truck/bus fueling stations, two power plants, etc. There does not appear to be a central location that would receive and store hydrogen for transshipment to end-use locations.

The funding statute, the Bipartisan Infrastructure Law, defines a hydrogen hub as a network of hydrogen producers and hydrogen consumers “located in close proximity.”  Instead, with this “hub,” hydrogen production sites span most of the state, and hydrogen consumers in San Diego and Lodi are 473 miles apart.

So much for Congress’ “close proximity” requirement.

Making Global Warming Worse

This hydrogen “hub” is going to make global warming worse. Here’s why.

This project is going to use electricity from 10 or more renewable production sites across California to make hydrogen, and then store and transport the hydrogen to, among other consumers, two or more power plants. In my prior column, I showed how the losses in converting renewable energy to hydrogen, storing and transporting the hydrogen, and then converting the stored medium back into electricity, would take 7 MWh of green electricity at the source to end up with 1 MWh of green electricity delivered to end-use consumers.

And that’s what will happen here. Every 7 MWh of renewable generation at production sites that otherwise would have been delivered directly to the grid, displacing natural gas generation, instead will be diverted to this hydrogen “hub,” ultimately becoming 1 MWh of renewable generation delivered to the grid. So, every metric ton of carbon emissions avoided at the point of consumption will result in 7 metric tons of incremental carbon emissions from non-displaced natural gas generation.

Does that make any sense to anybody?

Cost of Carbon Emission Reduction

This hydrogen “hub” is a $12.6 billion project. Let’s ballpark a 10% annual revenue requirement for return of (depreciation) and return on capital, so $1.26 billion annually. DOE says this hydrogen hub will reduce carbon emissions by “2 million metric tons per year.”

That can’t be so for the reason given in the prior section, but giving DOE the benefit of the doubt, if we do the math, that’s a cost of $630 per ton of carbon emission reduction.

That cost is a multiple of the per ton cost of dozens of other carbon mitigation options, including 10 in the energy sector alone, as this IPCC table (see page 1,254, Table 12.3, Energy Sector portion) shows. All listed options are $200/ton cost or less.

Detailed overview of global net GHG emissions reduction potentials (GtCO2-eq) in the various cost categories for the year 2030. | IPCC

Which begs the question, why spend many billions on a hydrogen “hub” that, even assuming DOE’s figures, still costs more than a multiple of myriad other carbon mitigation options?

Job Creation

DOE claims this hydrogen hub will create 90,000 permanent jobs. This appears to be typical sleight of hand that ignores the fact that what taxpayers must pay for this program will reduce their disposable income, thereby reducing their spending and thereby reducing the jobs their spending would otherwise support. And those would be jobs providing products and services that people actually choose to pay for, instead of jobs artificially created by government agencies using taxpayer money.

Let’s take an example: DOE says the hub will fund 5,000 hydrogen trucks and 1,000 hydrogen buses. But the truck drivers and bus drivers driving new hydrogen trucks and buses instead would have kept driving diesel/gas trucks and buses. No new jobs.

Water

Have I mentioned all the water that will be needed for the electrolysis to produce hydrogen (9 kg of ultrapure water for every 1 kg of hydrogen)? This in a state not known for having a lot of spare water. Just sayin’.

Backup for Well Water Pump

Speaking of water, DOE says it “will use hydrogen to provide backup power to community well water pumps to ensure clean drinking water during power outages.”

This use of taxpayer dollars is wrong for at least three reasons. First, the recipient, the Rincon Band of Luiseno Indians, is a small tribe (about 500 members) that owns Harrah’s Resort Southern California — an enormous hotel/casino/events center. This tribe does not need subsidies from the rest of us.

Second, the tribe’s water well pump already has backup generation in the form of a 130-kW diesel generator. DOE’s implication that the tribe would get backup generation it doesn’t already have is wrong.

Third, the tribe already is using taxpayer funds for a new solar/battery system. Is the plan to substitute some sort of hydrogen system for this solar/battery system? Or perhaps have three systems (in addition to the grid): the diesel generator, the solar/battery system and the hydrogen system? Yikes.

OK I’ll stop the hydrogen rant here.

P.S. Re. last column’s P.P.S. about “(What’s So Funny ‘Bout) Peace, Love, and Understanding,” I came across this live Elvis Costello cover where the Bangles show up. It seems like it’s over at four minutes but somehow rocks on. And oh yeah, the Boss with Bon Jovi. And Sheryl Crow covers it not too shabby. And Bob Geldof — thank you for Live Aid! — gives a reading that explains it before killing it. Thank you again Bob Geldof!

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

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Environmental Review of Maryland OSW Plan Completed

Federal regulators have completed their environmental review of a wind energy proposal off the Maryland coast, putting the US Wind project in line to be the 10th approved in U.S. waters. 

The U.S. Bureau of Ocean Energy Management said July 29 that the plan could yield up to 2.2 GW of emissions-free electricity if built as proposed. 

BOEM said it will post a notice of availability of the final Environmental Impact Statement on Aug. 2, triggering a waiting period of at least 30 days before it can issue a Record of Decision on the construction and operations plan submitted by US Wind. 

All nine of the records of decision issued so far have been approvals. 

US Wind is proposing a wind energy facility of up to 114 wind turbine generators rated at 14 MW to 18 MW each, up to four offshore substations and a meteorological tower on OCS-A 0490, an 80,000-acre lease area 10.1 miles off the northern Maryland coast. Seven of the original 121 turbine positions were deleted to create greater separation from Delaware Bay marine traffic. 

The nameplate capacity would be as much as 2.2 GW, and that electricity would be exported to three substations to be built in Delaware. 

The project includes MarWin, a 300-MW wind farm, and Momentum Wind, rated at 808 MW. Both hold offshore renewable energy credit (OREC) agreements with the state of Maryland. The remainder of the lease area would be built out in a third phase as additional demand arose. 

BOEM made the environmental impact statement (EIS) public in draft form in October 2023 and received 1,833 comments in response. 

The Maryland offshore wind final EIS follows a format similar to those issued for other projects, presenting a range of possible effects that construction and operation of the wind farms would have in a series of categories — sometimes positive, sometimes negative, sometimes both or neither. 

For example, birds could have increased foraging opportunities once wind turbines were installed and they could be killed by spinning blades. Jobs might be lost in the recreation and tourism sectors and jobs would be created in the wind sector. Environmental justice populations would suffer some disruption and could benefit from new employment and economic activity. 

The cumulative environmental impact with ongoing and future activities (including other offshore wind activities) also is predicted, and in some cases is more beneficial or more detrimental than the individual impact of one project. 

The EIS also looks at the future result of the status quo — of not building wind farms in OCS-A 490 — and finds that in some categories, continuation of present environmental trends might be as detrimental in their own way as would be building wind farms intended to counter those trends by reducing greenhouse gas emissions. 

The critically endangered North Atlantic right whale — poster cetacean for offshore wind opponents — is one such example.

The EIS estimates the project by itself would have minor negative impact on the whale but a major impact if considered in combination with existing baseline factors and environmental trends that would continue without construction of the facility. 

As with the reports prepared for other projects, the Maryland offshore wind EIS foresees potential major impacts for commercial fisheries; scientific research and surveys; and visual resources. 

MarWin and Momentum Wind are important pieces of Maryland’s strategy to reach its target of 8.5 GW offshore wind by 2031. Right now, they are the only pieces — Ørsted canceled the Maryland OREC contract for its two-phase 966-MW Skipjack project amid industrywide financial struggles. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.) 

In May, the state allowed US Wind to request contract revisions and higher compensation in an attempt to keep those two projects in the portfolio. (See Maryland Offers OSW Developer More Lucrative Terms.) 

The Biden administration’s push for offshore wind development continues. BOEM has scheduled an auction Aug. 14 for wind lease areas off the Delaware, Maryland and Virginia coastline estimated to hold the potential for up to 6.3 GW of electric generation. 

US Wind said July 29 that the EIS is a major milestone for its three-phase project, and said it expects BOEM to issue the record of decision in September. 

CEO Jeff Grybowski said in a news release: “We are well on our way to putting Maryland’s offshore wind goals that much closer to reality. We applaud BOEM for the comprehensive and thorough review of our federal permit application. We are now one step closer to securing all of our federal permits by the end of this year, and look forward to the day we can get steel in the water.” 

Italy’s Renexia SpA, a subsidiary of Toto Holding SpA, is majority owner of US Wind. 

Trade association Oceantic Network said the pipeline of approved U.S. offshore wind proposals will exceed 15 GW once US Wind gets its record of decision, and it noted that more than 5 GW already is under construction. 

CEO Liz Burdock highlighted the local and national relevance of US Wind in a news release: 

“Maryland has long seen offshore wind power as a key part of its energy and economic future, investing in a local offshore wind supply chain and the development of robust clean energy targets that have been driving the industry forward since its early stages. Today, the state has a commercial scale project nearing full construction approval and is poised to become a regional hub for offshore wind manufacturing and steel fabrication. Along with US Wind’s direct investment in Sparrows Point Steel, this offshore wind project will contribute to new, well-paying jobs across Maryland and throughout the supply chain.” 

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FERC Grants PG&E Incentives for 4 Transmission Projects

FERC on July 25 approved two incentives Pacific Gas and Electric requested to support work it will undertake with LS Power Grid California for four transmission projects included in CAISO’s 2021/22 transmission plan (EL24-107). 

In an order issued at its monthly open meeting, the commission found the projects satisfy the Order 679 requirements for incentive rate treatment because they will improve reliability and reduce congestion. Commissioner Mark Christie dissented in the 2-1 vote.   

FERC approved use of the Construction Work in Progress (CWIP) and the abandoned plant incentives for PG&E’s supporting work to interconnect and integrate the Collinsville, Manning, Newark and Metcalf projects into CAISO’s grid, which will help offset associated costs and address long lead times.  

After becoming sponsor, LS Power also was awarded transmission rate incentives for the projects in March 2023.  

The Collinsville Project consists of a new 500/230-kV substation, two new 230-kV transmission lines to the Pittsburg substation, looping in the Vaca Dixon/Tesla 500-kV line into the Collinsville substation and adding a series capacitor to the Collinsville/Tesla line.  

The project, which is estimated to cost between $475 million and $675 million, will mitigate a constraint on the Cayetano-North Dublin 230-kV line, increasing reliability and facilitating renewable generation in the northern Bay Area, according to PG&E. It’s estimated to cost PG&E $197.9 million to complete several updates, including constructing several lattice structures, new bays and line swapping, decreasing existing series capacitor banks, adding a telecommunications path and adding breakers.  

The Manning project will consist of a new 500/230-kV substation and two new 230-kV transmission lines to the Tranquility substation, looping the PG&E Panoche-Tranquility transmission lines and the Los Banos-Midway and Los Banos-Gates 500-kV lines into the Manning substation. It’s estimated to cost $325 million to $485 million and will mitigate the constraint on the Borden-Storey 230-kV transmission line, allowing for the advancement of renewable generation in the Westlands or San Joaquin areas, the order says. PG&E’s work supporting the project will cost an estimated $423.9 million for looping lines into the new substation, building new transmission lines, installing relays and switches on the Los Banos-Midway line and more.

The Newark project includes a new 500-MW HVDC line between two new LS Power convertor station facilities at an estimated cost of $325 million to $510 million. According to PG&E, the Newark project addresses CAISO’s forecast of significant load increases in the Silicon Valley area that will result in overloads in the San Jose 115-kV system. PG&E’s work supporting the project will cost another estimated $16.3 million and include installing a new substation bay at Newark substation, upgrading the Newark station ground grid and grading, constructing a 230-kV line with new insulators and hardware and implementing new telecommunications equipment.  

Finally, the Metcalf project will consist of a new 500-MW HVDC line between the two new LS Power converting station facilities and is estimated to cost $525 million to $615 million. PG&E’s work supporting the project is significant, costing $266.6 million and including constructing a 500-kV line, installing a 115-kV underground cable and expanding a portion of the Metcalf substation.  

‘Check-the-box’

PG&E argued that the CWIP incentive will help support the significant cost of the projects, which are projected at $904.7 million between 2024 and 2028 — a “significant portion of PG&E’s planned $9.1 billion in overall transmission spending during that period,” the order reads.  

The incentive also would help address the long lead time between 2024 and 2027/28, which is the earliest the projects are expected to go into service.  

“PG&E contends that requiring investors to wait a minimum of four years before receiving a return on their investments would diminish the attractiveness of these investments relative to other PG&E investments that have shorter lead times. Further, PG&E argues that allowing CWIP recovery will lower financing costs, which will decrease the total revenues paid by consumers over the life of the projects,” the order reads.  

CWIP recovery also would reduce the “rate shock” that could occur if the cost of the projects were accounted for only in the 2028/29 rate case.

But in a protest submitted to FERC, the California Public Utilities Commission argued that the CWIP incentive is harmful to California ratepayers by requiring “premature and excessive rate recovery.” When projects have longer lead times and higher costs than when forecasted at the time the incentive was granted, the incentives cost consumers more and provide a one-sided benefit, the CPUC said.  

If FERC granted the incentives, it should put up “guard rails,” the CPUC argued, including capping CWIP eligibility at the cost of the project and rescinding CWIP recovery as soon as CAISO’s original in-service date passes.  

Maintaining course with past dissent, Commissioner Christie also argued PG&E should not be awarded the CWIP and Abandoned Plant incentives.  

“The CWIP and Abandoned Plant incentives are nothing more than a transfer of wealth from consumers to transmission developers and risk from developers to consumers,” Christie said in his dissent. “It is long past time for the commission to revisit its ‘check-the-box’ practice of granting transmission incentives, including as set forth in Order No. 679. The longer the commission does nothing to address these unfair transfers of wealth and risk, the more consumers are exploited.” 

But FERC sided with PG&E in granting both incentives for all four projects without ‘guard rails.’  

“We find that PG&E has demonstrated that each of the requested incentives, and the package as a whole, address its risks and challenges for the support work that it will undertake in conjunction with the projects,” the order said.

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Texas Commission Rejects ECRS Rule Change

Texas regulators have rejected an ERCOT protocol change that took months of sometimes-contentious negotiations before the grid operator’s staff and stakeholders could reach a compromise that earned board approval. 

In taking up the rule change (NPRR 1224) that modified the ISO’s new ERCOT contingency reserve service (ECRS) product, the Public Utility Commission removed a proposed $750/MWh pricing floor. It also asked ERCOT to separately implement the revision’s trigger mechanism for the service (54445). 

The commission sided with staff’s determination that the operating reserve demand curve (ORDC), which uses scarcity pricing to value operating reserves, should be relied upon to generate “economically appropriate market pricing.” Staff said the offer floor “inappropriately supplants the role of the ORDC in pricing scarcity risk” and said the demand curve should remain the vehicle to price ECRS capacity and deployment risk until real-time co-optimization can be deployed. 

The ISO plans to add co-optimization of energy and ancillary services in real time in 2026. 

ERCOT COO Woody Rickerson said NPRR 1224 was originally drafted without an offer floor. It was expected, he said, “but we wanted to get market participant feedback on what the offer floor would be … the NPRR was written so that that offer floor can be filled in after market participant input.” 

“I thought you all were completely agnostic to that, to be honest,” PUC Chair Thomas Gleeson said. “Is it still fair to say that the part of this revision that is most important to ERCOT is the trigger?” 

“Yes,” Rickerson responded. “ECRS is a high-need reliability tool.” 

The trigger mechanism takes effect when there is a 40-MW power balance violation for at least 10 minutes. 

The rule change was approved by ERCOT’s Board of Directors in June and included the offer floor and trigger mechanism for the ancillary service product. ECRS procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. (See “Contentious NPRR Revising ECRS Passes over Monitor’s Objections,” ERCOT Board of Directors Briefs: June 17-18, 2024.) 

ERCOT’s Independent Market Monitor has opposed ECRS after it first was deployed in June 2023. It says the grid operator’s first new ancillary service in 20 years created artificial supply shortages that produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

Potomac Economics’ David Patton, whose firm serves as ERCOT’s IMM, again pressed his case against the protocol change. He made his third business trip to Texas in eight months to argue against the NPRR. 

“The market performance that was impacted by the deployment of ECRS in 2023 was calamitous. I’ve never seen something as bad as what happened,” Patton told the PUC. “The priority has to be to fix ECRS, not just iterate and improve and make it a little bit better. We know how to fix this. What the NPRR would do is institutionalize a fairly large share of the dysfunction that we saw in 2023.” 

Patton told RTO Insider the PUC’s decision was a “partial victory.” 

“The trigger mechanism, while it may be used in the near term, can be changed and improved by ERCOT if I can convince them that it is having unintended consequences. If the protocol revision had passed, we would be stuck with it,” he said in an email. “Ultimately, that decision had huge cost implications over the next two years.” 

Attorney Katie Coleman, who represents the Texas Industrial Energy Consumers lobbying group, agreed with the commission’s decision to remove the offer floor and allow ERCOT to address the deployment trigger. She called for a $100 floor during the board’s discussion. 

Coleman also agreed with Gleeson’s complaint that ERCOT’s board process “did not work” for him. Gleeson said he and Commissioner Lori Cobos, who both sit on the grid operator’s board, did not comment during the directors’ consideration of NPRR 1224 because they did not have all the information they needed. 

“I would argue that some of the most pertinent information I heard came in post-board decision. … I need to have all the information that I can have at the board because I think it is important for me to be able to tell the board what I think so that if they pass something, they know perhaps it may get rejected at the PUC. For me, that does a disservice to the board process,” he said. 

“Unfortunately, there was urgency to move something through the stakeholder process to try to get it implemented this summer, and as a result, some of the issues and analyses were not fully fleshed out before the board,” Coleman told RTO Insider. “We agree with [Chair] Gleeson that improvements are needed to make sure the board has all the information needed to make the right decision.” 

SPS Capacity Needs Partly Approved

The commission partly granted Southwestern Public Service’s request for additional capacity to meet SPP’s planning reserve requirement (PRM), approving three solar farms but rejecting a battery storage facility (55255). 

An administrative law judge in May approved SPS’s application for three solar facilities at existing plant sites in Texas and New Mexico offering 418 MW of nameplate capacity. However, the ALJ rejected a request for a 36-MW battery facility in New Mexico, saying SPS has failed to prove the facility is an economical solution to its capacity needs because it would add only an incremental amount of capacity relative to its $66 million cost. 

Gleeson filed a memo agreeing with much of the ALJ’s decision. He found fault with the conclusions that SPS “adequately considered” alternatives to the solar facilities and that its request-for-proposals process was conducted reasonably. Gleeson recommended adding a cost cap to the solar facilities, currently projected at just over $700 million, and agreed with the ALJ’s recommendation for a third-party review if the construction costs are 10% greater than projections. 

The PUC chair wrote that SPS’s “questionable” resource planning decisions placed the commission in a “difficult position.” 

“I believe a cost cap may be appropriate in this case because of SPS’s failure to adequately consider alternatives, which led them to the selection of a capital-intensive, non-dispatchable resource to satisfy their capacity needs,” Gleeson said. 

SPS filed in July 2023 to increase its capacity needs following SPP’s three-point increase in the summer PRM to 15%. The utility said the additional capacity would be needed as early as 2024 due to the retirement of aging natural gas facilities, the expiration of power purchase agreements, and projected customer load growth. (See SPP Board, Regulators Side with Staff over Reserve Margin.) 

The commissioners agreed SPS should ensure customers receive 100% of the solar facilities’ production tax credits as they are earned. 

Staff Begins Beryl Investigation

PUC staff has filed a memo outlining a proposed scope and approach to the commission’s investigation of Houston utilities’ response to Hurricane Beryl (56822). 

Staff is planning to send requests for information to electric and water service providers in the Greater Houston area and to invite generation companies, retail electric providers and communications service providers to submit the effects to their services and their response to the May derecho event and Beryl.  

They also are analyzing utilities’ emergency operations plans, vegetation management plans, infrastructure and storm hardening plans, after-action reports, and customer complaints. Their investigation will include reviews of storm preparedness and response best practices from infrastructure experts.  

A draft report is scheduled to be presented to the commission for its consideration during the Nov. 21 open meeting. A final report will be delivered to Texas Gov. Greg Abbott (R) and the state Legislature by Dec. 1. 

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BOEM Cancels Gulf of Mexico Wind Lease Auction

The second Gulf of Mexico wind lease auction has been canceled for lack of interest, but an unsolicited request has been submitted for wind lease elsewhere in the Gulf. 

The U.S. Bureau of Ocean Energy Management said July 26 that just one company expressed interest in the four lease areas that had been targeted for auction in September 2024. Two more auctions tentatively are scheduled in 2025 and 2027; BOEM said those may still go forward if there is industry interest. 

There is some industry interest, apparently: 

Also on July 26, BOEM announced that Hecate Energy Gulf Wind had requested to lease two areas southeast of Texas totaling 142,000 acres. They were not among the four areas that would have been offered in the second Gulf of Mexico wind auction this year. 

As required by the Outer Continental Shelf Lands Act, BOEM is issuing a request for competitive interest for the two areas Hecate is requesting.  

If BOEM receives one or more indications of interest from qualified companies, it may offer the two areas in a competitive auction. If BOEM gets no response, it may award Hecate rights to the areas through a noncompetitive lease issuance. 

Hecate Energy submitted a similar unsolicited request to BOEM in March 2022 for a lease area in federal waters off Washington state for a floating wind farm it called Cascadia Offshore Wind. 

Two years later, no such lease has been awarded, and BOEM could not immediately provide any information on the status of the request. 

Advantages and Challenges

Even amid the challenges the offshore wind industry is working through as it tries to build momentum in the United States, the Gulf of Mexico stands out for several reasons. 

Decades of shipbuilding and offshore fossil fuel development give the region the closest thing to a ready-made workforce and industrial base to support offshore wind that exists in the United States. (See IPF24: Louisiana Manufacturers Expand into Offshore Wind.) 

And there is interest in a new source of emissions-free electricity to produce green hydrogen in the Gulf region. 

But two years after the landmark Inflation Reduction Act, there still is no final tax guidance on which to base a green hydrogen financing scheme. 

Electricity is relatively cheap in the region, and state leaders have not been clamoring for offshore wind the way Northeast and California officials are. 

The seabed is softer than on the Atlantic and Pacific coasts, creating different considerations for turbine foundations. 

The wind typically is weaker in the Gulf than along the East and West coasts, except during the hurricanes that rip through each year. So, equipment must be designed simultaneously to optimize output in light wind and minimize damage in heavy wind. 

And of course, the young U.S. offshore wind sector has been reeling from supply chain constraints and soaring costs. 

Against this background, BOEM offered three lease areas in its first-ever Gulf offshore wind auction in August 2023.  

The auction ended quickly. Two companies submitted bids for one lease area, but only one advanced to the second round of bidding. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

RWE got rights to the 102,480-acre OCS-G 3733 — potential capacity 1,244 MW — for $5.6 million. 

By contrast, RWE and National Grid Ventures paid $1.1 billion for the 125,964-acre OCS-A 0539 off the New York-New Jersey coast — potential capacity 3,000 MW. That auction was held in February 2022, before the industry was slammed by macroeconomic factors. 

At least some of the factors that rendered the first Gulf of Mexico wind auction a dud apparently are still in play. 

BOEM said July 26 that it received 25 comments in response to the proposed sale notice it issued four months earlier but only one expression of interest in participating in an auction. 

Glass Half Full

Amy Krebs, vice president of offshore wind for Hecate Energy, said via email: 

“Hecate Energy is excited to see BOEM advance our request for an unsolicited lease in the Gulf of Mexico. Hecate has a long history of developing energy in the Gulf Region and sees the long-term potential for offshore wind in the Gulf of Mexico. This initiative, while still in the early stages, represents a significant step forward in our journey [toward] a sustainable energy future and demonstrates our commitment to driving economic development in the region.” 

BOEM took a forward-looking approach in announcing the news. Gulf of Mexico Regional Director James Kendall said in a prepared statement that BOEM will continue to explore the opportunities off the nation’s southern coastline: 

“The Gulf region benefits from great offshore wind resources and existing energy infrastructure. The interest from industry leaders such as Hecate and RWE demonstrates the commercial potential in the region.” 

National trade group Oceantic Network likewise focused on the positive — the continuing development of industry in the region to support offshore wind power elsewhere, if not immediately in the Gulf itself. 

Spokesperson Sam Salustro said: 

“The Gulf of Mexico is the U.S. offshore wind industry’s supply chain engine, providing the workforce, offshore expertise, vessels and fabrication yards that are building out our first East Coast projects, and is poised to become a major regional market of its own. Today’s decision moves offshore wind energy forward in a deliberate and sustainable manner for the region by creating pathways for key pioneering projects. This development enables critical support structures to advance, ensuring the development of a robust market that leverages the Gulf’s unique infrastructure and capabilities.” 

Greater New Orleans Inc. (GNO) on July 26 listed some of the pieces in motion: 

Louisiana is beginning to create a comprehensive offshore wind road map, the U.S. Department of Energy is assessing transmission needs in the region to support offshore wind, Louisiana has an agreement on two potential wind farms in state waters, and the regional supply chain is strong. 

GNOwind Alliance program manager Cameron Poole said in a prepared statement: “These are objectively exciting developments, and demonstrate the ingenuity being deployed to find creative solutions for OSW in the Gulf of Mexico. The proposal by Hecate Energy demonstrates continued interest by developers to serve the Gulf market, and [cancellation of the second BOEM auction] will ensure that future competitive opportunities to secure lease rights will be best aligned with regional and local activities that are crucial to the success of any offshore wind development.” 

Oceantic noted that it and the Pew Charitable Trusts both released favorable reports about offshore wind supply chain capacities already in place in the Gulf Region. 

Oceantic said 23% of 1,500 U.S. offshore wind supply contracts already signed have gone to Gulf-based firms and said nearly $1.3 billion worth of vessel construction and retrofit work has been commissioned in Gulf shipyards. 

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MISO Previews Future Projects to Improve System Planning

MISO has multiple planning topics to tackle on the horizon, with work involving an update of merchant HVDC interconnection procedures, making expedited transmission project reviews more manageable, and evaluating co-located load and generation seeking interconnection.

The RTO discussed the trio of subjects with stakeholders during an Interconnection Process Working Group (IPWG) teleconference July 23 and a Planning Subcommittee teleconference July 24.

Every-other-month Expedited Projects

MISO said it hopes to pivot to a bimonthly processing approach for transmission projects submitted by members for expedited treatment.

During the PSC call, Senior Expansion Planning Engineer Amanda Schiro said MISO wants to kick off an expedited project request window every other month. Schiro said the RTO needs more structure in the process, and an every-other-month schedule to study requests for system impacts would help it internally manage the increased volume of out-of-cycle projects.

Currently, MISO processes requests for projects that cannot wait until end-of-the-year approval through the annual Transmission Expansion Plan (MTEP) as they are received. The RTO originally hoped to roll out a quarterly expedited process but was met with stakeholder resistance. (See MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)

A bimonthly process would allow MISO to better manage its workload and the unpredictable nature of expedited project requests, Schiro said. She said members would be free to submit their expedited projects at any time.

“We understand that loads pop up at any time, so we do still want to have an on-demand submittal,” Schiro said.

MISO plans to study smaller expedited projects in batches while larger, complicated projects will get individual assessments. Schiro said MISO recognizes that different expedited requests will require different timelines for review, adding that the RTO has taken about 100 days to study some of its larger expedited projects.

Schiro said MISO intends to remove the requirement that projects necessitated by state departments of transportation need to enter the expedited process. She said such requests tend to be minor and often involve relocating a line to the other side of a highway. Those projects would be routed instead to MISO’s MTEP portal, where the RTO will check them over and allow them to proceed.

MISO also wants fewer dedicated technical study task force meetings, where expedited project reviews are discussed. Schiro said it is burdensome to compile materials and plan meetings, and the RTO wants the meetings to similarly transition to an every-other-month cadence for staff to discuss groupings of projects.

The RTO said that when it first developed its expedited process, it fielded about four to six additional studies per MTEP cycle, with project approvals allowing quick funding for immediate reliability needs. Over the past three years, however, MISO said larger, more complex load additions with quick turnaround times have become the main reason for growing expedited treatment requests. MISO this year is expecting at least 30 expedited requests.

Invenergy Seeks Changes to HVDC Connection Procedures

Having submitted its Grain Belt Express for interconnection to the MISO system, Invenergy has approached MISO with ideas to improve its process for incorporating merchant HVDC.

Invenergy’s Arash Ghodsian told the IPWG that as Grain Belt has become the first to navigate MISO’s interconnection process, it has “come across a number of areas for improvement.”

Merchant HVDC lines that want to connect to the MISO system must follow Attachment GGG of the tariff to gain injection rights. The process looks familiar to the RTO’s interconnection process: Developers must pay study deposits, submit to studies and agree to pay for network upgrades if necessary.

However, Ghodsian said MISO’s HVDC interconnection procedures do not include a provision that allows an HVDC developer to utilize its connection to the grid before all network upgrades are complete. The RTO allows such limited operations for projects in its generator interconnection queue.

Ghodsian said Invenergy hopes MISO and stakeholders will discuss that recommendation and other areas for improvement at upcoming IPWG meetings.

Grain Belt Express struck an effective transmission connection agreement with MISO in February.

NextEra Makes 2nd Overture for Bundled Studies

MISO and stakeholders will likely consider a dedicated study and registration process for new generation contingent on large loads in the months ahead.

NextEra Energy’s Erin Murphy again said her company and others want MISO to create a designated market participation and registration for co-located load and generation behind the same point of interconnection. (See “NextEra Asks MISO to Study New Load and Generation Duos,” MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)

During the PSC teleconference, Murphy said MISO currently has a “disconnect” between the load growth studies completed under annual MTEPs and its studies for new generation through its interconnection queue. She asked MISO to “harmonize” how it considers generation contractually dependent on new load to be “poised and ready” for the rise of data centers.

NextEra has suggested the connected studies should be reserved for “hyperscale loads” and that MISO could institute a minimum size requirement to consider the studies simultaneously. The RTO could also make generation interconnection agreements conditional on the new loads, Murphy said.

Evaluating load and generation together in some cases will result in more efficient and economical study results, she argued. NextEra is looking to collaborate with stakeholders to bring a recommendation on how to best connect load studies to their dedicated generation.

Coalition of Midwest Power Producers’ Travis Stewart said NextEra’s idea is imperative to reflect the new load growth reality in the footprint.

“Large loads are popping up all over the country, and this would bring MISO in lockstep with other regions,” Stewart said.

Other stakeholders said they worried that load-dependent generation studies would complicate a queue process that MISO is currently trying to streamline. They said load might need to put up securities to mitigate queue restudy costs.

Murphy said the goal of the proposal is to provide more certainty in the interconnection process, not elicit more restudies. She also said MISO could place some parameters on how far generation can be sited from the load before they are no longer considered in tandem.

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FERC Accepts All 6 ISO/RTO Order 895 Compliance Filings

WASHINGTON — FERC on July 25 approved all the jurisdictional ISO/RTO compliance filings with Order 895, which established rules for sharing credit information among the organized markets.

Issued in June 2023, Order 895 directed the six grid operators to create procedures for sharing credit information about wholesale market participants with each other. The order is intended to “improve their ability to accurately assess market participants’ credit exposure and risks related to their activities across organized wholesale electric markets.”

FERC said the rules will help prevent market participants from defaulting, thus forcing the ISO/RTOs to collect the costs from other market participants. Before the order, the grid operators’ own confidentiality rules would have prevented them from sharing market participants’ information.

“Market participants increasingly operate in multiple organized wholesale electric markets, whether directly or through affiliated entities, and their trading activities have become more complex and sophisticated,” FERC said in Order 895. “These developments have complicated the ability of any individual RTO/ISO credit department to develop a complete, accurate and up-to-date picture of a market participant’s overall financial condition due to real or perceived barriers to information sharing among RTOs/ISOs.”

FERC found that CAISO’s (ER24-155), ISO-NE’s (ER24-138), NYISO’s (ER24-95), PJM’s (ER24-156) and SPP’s (ER24-289) filings satisfied the order’s requirements, including that they protect the data they collect from other markets. Their proposals went uncontested and, in some dockets, without any interventions.

While the commission found that MISO’s proposal allows it to share information and to use credit information received from other ISO/RTOs, and the RTO said it would treat such information from another market as confidential, such language was absent from its tariff revisions (ER24-165). FERC directed MISO to submit a compliance filing in 60 days spelling that out in its tariff.

The accepted revisions went into effect the next day. Though they were issued at the commission’s first open meeting with new Commissioners Lindsay See and Judy Chang, they did not participate in the orders.

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FERC Accepts SPP Congestion Hedging Changes

FERC filed a letter order July 25 accepting SPP’s proposed tariff revisions to implement congestion hedging improvements, ending a journey through the stakeholder process that began six years ago (ER24-1775). 

The commission found SPP’s proposal will “improve market participants’ ability to hedge congestion costs by allowing SPP’s models to reflect congestion more accurately; allocating [long-term congestion rights], [incremental LTCRs] and [auction revenue rights] more broadly and equitably among eligible entities; and distributing surplus auction revenues more equitably.” 

SPP’s change request is a result of the stakeholder-driven Holistic Integrated Tariff Team’s work in 2018/19. The team’s charges included developing a high-level policy recommendation that aligns the grid operator’s transmission planning processes and resource adequacy needs with its markets and tariff requirements. 

Staff and stakeholders developed a package of eight congestion-hedging policies that were approved by the board and state regulators in February. (See “Congestion-hedging Policies’ Implementation,” SPP Board of Directors/Members Committee Briefs: Feb. 5-6, 2024.) 

SPP said the changes better align the network models it uses in the simultaneous feasibility test with the studies it uses to grant transmission service. That will prevent some transmission paths from not capturing all congestion and other paths that look feasible but do not offset the congestion experienced by load.  

The RTO is changing the process for awarding LTCRs and ILTCRs and the annual ARR allocation of ARRs by using a two-step, single round process in the second round of the LTCR allocation, knocking off two rounds. Eligible entities will be allowed to nominate 50% of their ARR nomination cap, reduced by the LTCRs awarded. Entities that receive a higher number of LTCR awards will nominate fewer ARRs in the first round of the ARR allocation. 

Also, SPP will break the simultaneous feasibility test performed during the second round of the LTCR/ILTCR allocation and the first round of the annual ARR allocation into five equal subrounds. Because breaking the simultaneous feasibility test into smaller increments makes it less likely that large portions of awards will go to a single entity, LTCR/ILTCR and annual ARR awards will be allocated more broadly and equitably. 

The grid operator is changing the distribution of surplus auction revenues by awarding them in greater proportions to eligible entities that received a lower proportion of LTCRs and ARRs tied to firm transmission service. The new approach will be phased in halfway into the first year (2025/26) to reduce the effect of revenue shifts. 

The revisions exclude transmission service reservations that do not source at a resource or a resource hub in the commercial model from being verified and used for LTCR and ARR nominations. SPP will apply the same exclusion when assessing grandfathered agreement transmission rights, and transmission service reservation holders will be allowed to update existing services’ sources to specific resources or resource hubs in the commercial model without triggering an aggregate transmission service study process. 

SPP’s Market Monitoring Unit said the grid operator’s proposal will create more equity in allocating ARRs, LTCRs and ILTCRs and a more equitable distribution of surplus auction revenue among market participants owning firm transmission rights. It supported the revised method of distributing surplus auction revenues.   

Intervening in the docket were American Electric Power Service Corp., on behalf of its affiliates Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission Co. and AEP Southwestern Transmission Co.; Evergy Kansas Central, Evergy Metro and Evergy Missouri West; Kansas Electric Power Cooperative; Lincoln Electric System; Midwest Energy; Missouri River Energy Services; Omaha Public Power District; Public Citizen; Western Farmers Electric Cooperative; and Xcel Energy Services, on behalf of affiliate Southwestern Public Service Co. 

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DC Circuit Declines Entergy Challenge of MISO Seasonal Accreditation

The D.C. Circuit Court of Appeals rejected Entergy’s challenge of MISO’s seasonal capacity accreditation and generator outage rules, two years after FERC approved the rules.

The court in a July 26 order decided FERC adequately explained why it allowed the new capacity accreditation and denied Entergy’s petition for review (22-1335).

Entergy argued that MISO’s new capacity accreditation would result in volatile and fluctuating capacity scores and that MISO’s seasonal outage rules for generators were burdensome.

MISO’s capacity accreditation assigns values based on resources’ performance over the past three years. The accreditation calculation gives a heftier, 80% weight to the 65 hours in a year when supply is the tightest and gives all other hours in a year a 20% weight.

Entergy contended MISO’s method over-relied on just 65 hours, and a generator’s accreditation could be tremendously affected if a planned outage happened to occur during some of the riskiest 65 hours. The company made similar arguments when requesting a rehearing of FERC’s 2022 approval. (See Regulators, LSEs Ask FERC to Reconsider MISO’s Seasonal Capacity Accreditation.)

But the D.C. Circuit decided FERC appropriately evaluated the accreditation style using a MISO-created analysis that compared existing and proposed accreditation methods to actual resource availability over 11 days containing emergency conditions in 2021. MISO found its old methodology overestimated resources’ offerings anywhere from 8 to 22%, while its new process was off by just 1%.

The court said FERC was correct to assume MISO’s new accreditation would be “more accurate than its prior approach when predicting resource performance during periods of highest demand.”

Entergy argued MISO’s 11-day sample size was too small. But the court said its hands were tied on considering MISO’s sample size because Entergy didn’t specifically raise that concern in its rehearing request with FERC. The court cited the Federal Power Act’s “unusually strict” exhaustion requirement.

The court also noted MISO uses a three-year rolling average when taking stock of a resource’s availability for accreditation, reducing year-to-year accreditation volatility.

“If bad luck besets a resource one year, the impact of such bad luck is blunted by the fact that other years can help balance out an anomalous season,” the court said.

The court didn’t see anything amiss with MISO’s generator outage length and notice requirements, either. It agreed with FERC that MISO’s 31-day limit “would give generators enough time to perform maintenance, while also ensuring that generators would be online for the majority of each season.” It disagreed with Entergy that the threshold would hinder necessary, extended outages.

MISO requires capacity resource owners either must acquire replacement capacity or pay penalties if they are offline for more than 31 days in a season and that they must notify it 120 days in advance of planned outages to be exempt from accreditation reductions.

“FERC reasonably explained that owners of such resources have four options: shortening maintenance; acquiring replacement capacity; opting out of the capacity market for a season while maintenance is undertaken; and scheduling maintenance so that it straddles two seasons, enabling planned outages of up to 62 days in length,” the court said. “As FERC explained, it is unfair for resources to go offline for more than 31 days in a season when distributors have paid for the resource’s commitment to supply electricity during that season.”

The court further said it made sense for MISO to require notification of outages before the start of a season so it can anticipate capacity supply.

MISO began using the seasonal, availability-based capacity accreditation in the 2023/24 planning year. FERC last year rejected Entergy’s attempts to secure waivers for two of its plants so it wasn’t affected by MISO’s accreditation rule, which assigns thermal units a zero-capacity credit when they take longer than 24 hours to start up. (See FERC Rejects MISO South Waiver Requests from MISO Accreditation Standard.)

Despite MISO’s relatively recent move to its current accreditation method, it isn’t here to stay for long. MISO again plans to modify its accreditation style so nearly all resources are valued based on a combination of probabilistic and historical availability. (See MISO: New Capacity Accreditation Filing Imminent.)