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November 13, 2024

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MISO Says Risk Driving It to LMR Reorganization, Stronger Requirements

CARMEL, Ind. — MISO said with resource adequacy risks at its doorstep, it may need to place tougher requirements on its load-modifying resources and devise new, nonemergency means of using the load offsets that cannot meet new performance standards. 

During a May 22 Resource Adequacy Subcommittee, MISO’s Neil Shah said he expects the grid operator will use LMRs differently from how they’ve been used in the past to aid reliable grid operations. He said the RTO plans to “redefine the LMR product” and “remap” its load management that can’t meet qualifications into potentially new resource modes that can be used during nonemergency conditions. The LMR category going forward might contain only those resources that can be ready within 30 minutes, staff suggested.  

Shah said MISO still plans to draw on “all types of resources both on the demand side and the supply side.” He said reserves that cannot meet new LMR standards will still be used to aid reliability in its markets, albeit differently.

“We see the grid is transforming at a rapid pace. We see the risk patten changing,” Shah said, adding that the LMR construct must change with it. 

Shah said that since 2007, LMRs have been used strictly during emergency conditions. LMRs are out-of-market voluntary response resources, Shah said, which are “guaranteed capacity market payment regardless of actual performance.” He said when MISO begins issuing capacity advisories and emergency alerts, LMRs sometimes will self-schedule reductions, and because MISO isn’t aware of the load offsets until after they occur, it complicates the ability to estimate needs before peak hours.  

Shah said MISO plans to present its new approach to LMRs at its Resource Adequacy Subcommittee’s July meeting. 

Sustainable FERC Project’s Natalie McIntire asked that MISO find ways to “maximize” the resources that might not be able to make the LMR cut. 

Michigan Public Power Agency’s Tom Weeks said it might be simpler for MISO to remove the requirement that it be in an emergency before LMRs can be accessed. He also said he wished MISO would “weed out bad actor” LMRs that don’t provide load reductions as promised.  

“Instead of using a scalpel to correct the issue, MISO is pulling out a bone saw and doing Civil War-like medicine to cut off a limb,” Weeks said.  

Shah acknowledged MISO needs better-defined auditing and monitoring standards for its LMRs. He repeated that MISO is open to creating a new market product to make sure participants can make use of longer-lead demand response offerings. However, MISO’s Zak Joundi later said MISO prefers to route nonemergency LMRs into one of its existing participation categories. 

Shah said MISO can examine its current Demand Response Resource Type I participation model to make sure it’s still useful to participants. If not, the RTO can make tweaks, he said.  

“It’s MISO’s job to make sure that it can make use of the resources available to it,” WPPI Energy’s Steve Leovy said. He argued that MISO shouldn’t need strictly 30-minute LMRs and that it should activate emergencies a few hours beforehand when it requires demand response. MISO should expect some level of inefficiencies during emergencies, he said.  

“We’re talking a few times a year during severe conditions … to keep the system intact,” Leovy said.  

“Managing a 15-state footprint is incredibly complicated. When you get into real-time emergency conditions, more simplicity is needed in the design,” Executive Director of Market Operations JT Smith said.  

Smith said the problem of when LMRs could deliver wasn’t present 10 years ago because MISO had ample resources. Now, he said MISO’s “entire reserve fleet is sitting behind an emergency call.”  

MISO initially was slated to use summer to design a new capacity accreditation for its LMRs; however, it said it was persuaded by stakeholders to pause on remodeling accreditation in favor of redrafting the LMR rulebook.  

LMRs were not included in MISO’s recent filing to implement a new capacity accreditation that would accredit resources based on their projected availability and historical performance during periods of high system risk. (See Stakeholders Deliver Negative Reactions to Proposed MISO Capacity Accreditation at FERC.)  

Before it announced the pivot, MISO said it considered splitting LMRs into emergency and nonemergency resources, giving 100% capacity credit to more nimble, emergency LMRs and apply a sliding scale to nonemergency LMRs that would reduce capacity credits as response times rise. 

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FERC Watchers Digest Order 1920 and Forecast its Future

The ultimate future of FERC Order 1920 depends on rehearing, implementation and inevitable litigation, but after reading through the order itself in the past week, many stakeholders see it as an important step forward in expanding the grid. 

FERC issued the 1,364-page order on a 2-1 vote May 13, with Commissioner Mark Christie (R) filing a dissent and countered by a joint concurrence from Chair Willie Phillips (D) and Commissioner Allison Clements (D). (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)  

The order requires regional transmission planners, including ISOs and RTOs, to plan at least 20 years ahead of time using multiple scenarios while taking into consideration several benefits. Their cost allocation plans for projects must ensure only customers who receive those benefits pay for the projects. 

“The status quo is not working, and this stuff is hard,” former FERC Chair Neil Chatterjee (R) said. “I think that Commissioner Christie raised a lot of significant points in his dissent that I need to think through. I think he’s probably right on a lot of it. But the reality is, somebody’s got to make a tough call. And I commend Chairman Phillips for making the tough call here.” 

Chatterjee said the issue has bounced back and forth between Congress and FERC, and one of the two needed to act to move the ball forward. 

“It’s a 1,300-page order; there is a lot to unpack,” Chatterjee said. “But from what I know of it to date, I honestly believe had I still been on the commission, I would have voted for it.” 

Outside of claims that the order is aimed at implementing President Joe Biden’s green energy policies, much of Christie’s concerns have to do with the impact on consumers. Devin Hartman, of the conservative think tank R Street Institute, argued that consumer response to FERC’s rule would determine how far his arguments go. 

“The big thing will be whether the consumers see the proactive and more comprehensive benefits approaches as leading to more economical transmission development than the status quo,” Hartman said. 

Regional economic transmission projects have generally done well on the cost-benefits front, saving consumers plenty of money, but consumers have been against the general rise in transmission rates, as most spending in recent years has gone to local projects that address specific reliability needs, he added. 

The National Association of Regulatory Utility Commissioners expressed disappointment with “the significantly diminished state role” envisioned in Order 1920. But the organization represents 50 states, and some of them are supportive, such as Michigan Public Service Commission Chairman Dan Scripps. 

“You’re going to have a trade-off any time you do interstate infrastructure planning on a consistent basis across state lines; you’re going to gain more efficiencies, but you’re going to lose some autonomy of those states,” Hartman said. 

The Electricity Consumers Resource Council, which represents large industrial customers and is “resource-neutral” in outlook, found the rule to be generally positive for consumers, said CEO Karen Onaran. 

But Onaran’s predecessor, Travis Fisher, who is now with the Cato Institute, wrote a critical take that argued Order 1920 represents FERC putting its thumb on the scale to help build out renewables. 

It is unfortunate that the partisan politics around green energy have “hijacked” the transmission issue because the grid needs to be expanded regardless, Onaran said. 

“I think for the Republican side, we just need to emphasize — especially as industrials are looking to expand their operations onshore in the U.S. — we’re going to need reliable service,” Onaran said. “And we’re going to go to those regions that have favorable regulatory policies that do look at expanding the grid that can support our operations, regardless of what the generation choices or availability is; we’re just going to need to get access to a lot more energy.” 

Even when it comes to the grid’s transition to more green power, Chatterjee said he sees the politics eventually working itself out. 

“I do think in the coming years that we will get to a point where red supply is feeding blue demand,” Chatterjee said. “Where you have a lot of this renewable capacity is in red states, and the demand for that clean energy is going to be in blue states. And I don’t think I’m being naive about this; I think that will fundamentally alter the politics around climate.” 

While Chatterjee did not like how the Inflation Reduction Act was passed in Congress, it was good policy to onshore the supply chain for renewable energy, which should help make that future possible, he added. 

How the Rule Will Change Cost Allocation

Supporters of the rule see little difference in transmission built for renewables, or that needed for reliability and economics. 

“It’s not any one driver behind it; it’s multiple drivers,” said WIRES Group Executive Director Larry Gasteiger. “And I think even if you exclude one of those drivers, you still have plenty of other things that are pushing the need for more transmission. There’s going to be some overlap between some of them. If you build a line to deal with a clean energy mandate or integrating more renewables, you may wind up getting more resilience out of the system and enhanced reliability; you may be able to meet some increasing load needs.” 

That has already played out, with the lines New Jersey is paying for under FERC Order 1000’s State Agreement Approach to interconnect its initial tranche of offshore wind farms, Abraham Silverman, of SilverGreen Energy Consulting and a former state Board of Public Utilities staffer, said in an interview. 

“When PJM did the modeling for the State Agreement Approach that New Jersey ultimately selected, they determined that they were benefits in … three other states,” he added. 

Under the currently effective transmission planning and cost allocation regime in PJM, no other option is available, and New Jersey will have to pay for all of those transmission lines despite benefits flowing to other states. Order 1920 requires PJM to plan for binding state policies like New Jersey’s offshore wind targets. 

“Now there’s an option on cost allocation, which is if the project meets certain benefit-to-cost ratios, then the costs are socialized across the entire grid,” said Silverman. “If the proposed project doesn’t meet the 1.25 benefit-to-cost ratio, then states can get together and voluntarily allocate those costs.” 

States will have a chance to decide how such lines are allocated, but Silverman said that if they were to just stick to the current SAA, then the commission could reject that because it would leave beneficiaries that are paying nothing. 

“Now, they’re only required to pay up to the benefits that they receive, and we’re not talking carbon benefits, or anything else,” Silverman said. “We’re really talking production cost; reliability; other sort of very tangible benefits.” 

Grid Strategies President Rob Gramlich likened the dispute between the three commissioners on cost allocation to getting the check after group dinner. 

“The way I think it’s easiest to think about is if you’re at a restaurant, should you pay for what you eat, or should you pay only for what you ordered?” he said on a webinar with reporters. “And one commissioner thinks you should only pay for what you ordered. And … the majority said, ‘No, you have to pay for what you eat.’ And it’s really just that very basic principle.” 

Part of the reason the majority allowed regional planners like RTOs to file their own cost allocation rules that could even overrule the states is because legal precedent from a 2002 case, Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, said in an interview. 

“Basically, the Federal Power Act is written in such a way so as to give transmission owners the right to file any changes in their rates,” Peskoe said. “And so, FERC was concerned that if it gave the state regulators equal rights, it might be infringing on the utilities’ rights to file rate changes.” 

Commissioner Christie argued that legal precedent would not be a problem in litigation if states got the right to file cost allocation rules of their own. Peskoe said he agreed with that interpretation. 

While that would mark a big change for PJM and some other markets, Brattle Group Principal Johannes Pfeifenberger said that MISO’s Multi-Value Projects have proved very popular even with red states in its footprint. 

“MISO did a good job explaining how their states benefit from the Multi-Value Projects, and then has also shown that the portfolio of projects they have come up with benefits each state more than the postage-stamp cost allocation,” Pfeifenberger said. 

How Far Will Regions Take the Rule?

One open question is how the rule will be implemented in different regions. 

Order 1000 required changes to transmission planning and cost allocation around the country, but only some regions effectively used it to cooperatively build out their grids. 

“FERC can take the horses to the water but can’t make them drink,” Pfeifenberger said. “How the regions respond to it will be different, no doubt. And some of them will take this as an opportunity to really improve the planning process to create low-cost transmission solutions. And other regions will just comply with the letter of the order and implement processes on paper that don’t really do anything in the real world.” 

The regions are going to have a lot of discretion to implement the rule, which is the case for nearly every major FERC rule, said Silverman. 

“How you quantify benefits is going to be something that each individual public utility transmission provider is going to have to do,” he said. “How you incorporate some of the more discretionary pieces of state policies into the transmission planning — the scenario-building process is going to be absolutely key. And then, of course, at the end of the day, you are only as good as the desire to build new transmission.” 

The rule gives regions more tools in the toolbox, but it does not necessarily require their use, he added. 

Former FERC Chair Jon Wellinghoff (D), who ran the commission when it issued Order 1000, agreed that it was time for an update to its transmission rules. 

“FERC just needs to ensure … that those rules are adequately drafted so that there is clear direction to the ISOs as to what they should be doing,” Wellinghoff said. “I mean, FERC has tremendous power there.” 

The chair can convene the ISOs and RTOs and other regions and explain what the commission expects to see as its rule is implemented, he added. 

Wellinghoff also argued that FERC needs to ensure that Order 2222 is fully implemented alongside Order 1920, as the growth in electric vehicles and other distributed energy resources needs to be fully accounted for. With millions of EVs hitting the road in the coming years, FERC needs to get that rule right so they can be an asset to the grid instead of a burden on it, he said. 

Rehearing and Appeal?

A rule this far reaching is going to have requests for rehearing, likely even from parties who largely support it but want to see something changed.  

For example, while WIRES supports the planning and cost allocation changes, Gasteiger said it was disappointed the final rule did not go as far on reinstating the federal right of first refusal as the proposed rule did. 

Christie’s dissent lays out a “great roadmap” for parties who support his position to follow on appeal, Chatterjee said. 

One major issue on appeal is which circuit court gets the case, noted Harvard’s Peskoe. Opponents of federal rules like to go to the 5th U.S. Circuit Court of Appeals in Texas because it has handed down decisions against Biden administration policies previously, he said. But to get it appealed to a specific circuit, opponents need to find an appropriate party located in its territory. 

Most FERC cases are adjudicated in the D.C. Circuit Court of Appeals, and the commission likely would prefer it there as the judges have experience with the issues, Peskoe said. 

Another major issue is the changing precedents in federal courts, with the Supreme Court considering cases that could overturn the Chevron doctrine of deference to “expert agencies,” which is how the D.C. Circuit upheld Order 1000. (See Supreme Court Hears Oral Arguments on Overturning Chevron.) 

“So, it’s possible that the litigants will attack first authority in this case, use this rule as vehicle for a broader attack on FERC that could undermine flexibility to regulate utilities going forward,” Peskoe said. 

Christie raised the Chevron issue in his dissent, and he also argued FERC’s rule went against the newer “major questions doctrine” that came out of West Virginia v. EPA (which was argued by FERC nominee Lindsay See, solicitor general of West Virginia). 

Litigation against FERC rules of this size and scope is almost a “rite of passage,” Americans for a Clean Energy Grid Executive Director Christina Hayes said on a webinar hosted by the American Council on Renewable Energy. 

Order 1920 is built on nearly 30 years of precedent dating back to Order 888 that have opened up the grid and led to significant cost savings for customers, enhanced resource adequacy and other benefits, she said. 

“This is built on very stable ground in that there’s so much significant precedent supporting it,” Hayes said. “Were this to be overturned, it would really remake the electrical industry and in ways that are hard to contemplate. For that reason, for the stability of the system, I imagine that there are significant forces that would support upholding this rule.” 

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Manchin not Ready to Give up on Bipartisan Permitting Bill

Sen. Joe Manchin (D-W.Va.) is not ready to give up on getting permitting legislation out of the Energy and Natural Resources Committee and to the chamber’s floor, he said in his opening remarks during a May 21 hearing on the opportunities and risks of growing electricity demand in the U.S. 

Approved May 13, FERC’s long-awaited Orders 1920 and 1977 address regional transmission planning and the commission’s backstop permitting authority but will only “help with one aspect of one part of a bigger set of grid permitting problems,” said Manchin, who chairs the committee. “They are a Band-Aid on congressional inaction.” (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

Manchin said he has been working with Sen. John Barrasso (R-Wyo.), the committee’s ranking member, on a permitting bill, and “we finally have language. We want to start sharing that language with everyone [so] that people can see where we are and hopefully that we can get our act together.” 

Sen. Joe Manchin (D-W.Va.) | Senate ENR Committee

Accelerating permitting was one of several familiar themes raised at the hearing, which primarily served as an echo chamber for the argument that meeting rising electricity demand from new factories and data centers across the U.S. will require not only keeping existing coal- and natural gas-fired power plants online, but also building more. 

EPA’s recent rules on cutting carbon emissions from existing coal and new natural gas plants were a particular target for both Manchin and Barrasso, who represent major coal-producing states. Already facing legal challenges from a group of Republican-led states and an industry trade association, the rules could require coal-fired plants without some form of carbon capture to close by 2039. (See Republican-led States Sue EPA over Power Plant Emissions Rule.) 

“These plants play a major role in ensuring electric reliability,” Barrasso said. “They also make electricity more affordable. President Biden doesn’t seem to care at all. He wants the cost of complying with EPA rules to be high. He wants to force operators to shut down these plants before the end of their useful life. It is a disgrace. We cannot regulate our way to more electric generation.” 

That additional generation is needed, Barrasso said, to keep the U.S. ahead of China in the emerging competition for dominance in artificial intelligence. China is continuing to build coal-fired plants to power its data centers, while the U.S. is closing down plants. “The president’s opposition to coal, to natural gas and even to hydropower … is a white flag. It is … an act of surrender to China,” he said. 

Sen. John Barrasso (R-Wyo.) | Senate ENR Committee

Both lawmakers also pointed to NERC’s recent summer assessment warning that extreme heat waves could put reliability at risk in some regions. (See NERC’s Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

Witnesses at the hearing generally provided variations on the same core themes: the need for reliable power to meet increased demand and rising concerns that the U.S. grid will not be able to deliver. 

To a certain extent, the U.S. electric system has fallen victim to the success of the Infrastructure Investment and Jobs Act, Inflation Reduction Act, and CHIPS and Science Act, all of which have catalyzed new investment in domestic industry and manufacturing, but also new demand, said Benjamin Fowke III, interim CEO of American Electric Power. 

“Just a few years ago, a large industrial manufacturing facility might require 100 MW,” Fowke said. “A facility that size would typically be one of a kind in a region, would be the major source of economic activity for that region. Now it is common for a single data center to require three [or] up to 15 times this amount of power for a single site.” 

Demand growth related to data processing could double nationwide in three years, he said. FERC, other federal agencies and state officials should collaborate “to evaluate the establishment of a central planning authority focused on reliability and directing FERC to ensure that viable reliability safety valve mechanisms are in place to prevent premature plan retirements,” Fowke said. 

Congress should also work to expedite permitting of resources ― “new 24/7 dispatchable and clean energy” ― that utilities identify as critical for system reliability, he said. 

Mark P. Mills, founder and executive director of the National Center for Energy Analytics, went further. “The fastest way to increase power supplies ― because we’re talking about demands that are occurring in the next few years, not decades ― it’s not things we don’t know how to build, but things we know how to build,” he said. “The best construction of dispatchable power will come from gas pipes and gas turbines. They’ll be the primary source of new supply. 

“This will be true with the United States, [in] almost every state; and it’s also true in Europe. It’s what’s happening around the world, but especially here,” he said. 

The Cost of a Tow Truck

Speaking for big industrial power users, Karen Onaran, CEO of the Electricity Consumers Resource Council, said U.S. industry could need an additional 36 GW of power by 2030, which will require right-sizing the grid and reducing regulatory barriers. She also criticized EPA’s power plant rules, saying they “further complicate a tenuous situation on our grid,” impeding access to affordable and reliable energy, she said. 

“We cannot afford to take any options off the table right now,” Onaran said. “We need all-of-the-above resources, and we need the infrastructure to support those resources. We need an agile and flexible grid that can manage variable supply, as well as variable demand. Demand is going to change [its] profiles.” 

Scott Gatzemeier, corporate vice president for front-end expansion at Micron Technology, spoke of the memory chip maker’s need for firm, 24/7 power and its efforts to reduce its power demand as it builds out new capacity for energy-efficient chips in New York, Virginia and its own home state of Idaho. 

The company’s site in Onondaga, N.Y., is 40 miles north of a nuclear power plant “with a direct line connection to a 345-kV substation across the street from [our] site,” Gatzemeier said. “Reliability of the system is incredibly important [for] semiconductor fabs because a small millisecond blip in our power would take down our factory for up to a week by interrupting processing.” 

For its Idaho facility, Micron is waiting for Idaho Power’s Boardman-to-Hemingway transmission line, which will allow bidirectional flows of clean power — hydro and wind — with the rest of the Pacific Northwest. The project has been in development and permitting since 2007 and is now waiting for final federal and state notices to begin construction, according to a project timeline on Idaho Power’s website. 

At the same time, Micron has committed to use 100% renewable power at its U.S. factories by the end of 2025. Gatzemeier said in his written testimony that its customers are always pushing it for more energy-efficient chips. Customers are reporting that Micron’s most recent memory chip, designed for AI, uses 30% less energy. 

One of the last senators to speak, Sen. Angus King (I-Maine) said the hearing’s discussion was missing the critical role of climate change in the energy transition. 

Sen. Angus King (I-Maine) | Senate ENR Committee

“We’re only talking about half the equation,” King said. “We’re like in a car on a railroad track with a train coming toward us, and we’re talking about the cost of a tow truck. The cost of not addressing climate change dwarfs the cost of addressing climate change. … 

“To act like the transition is just something we’re doing because it’s a nice thing to do or because some elite group says we should do it is just not accurate.” 

From grid-enhancing technologies to pumped hydro storage to old-fashioned conservation, other options exist for meeting increased demand, he said, but permitting reform will be the key. 

Speaking to reporters May 13, Senate Majority Leader Chuck Schumer (D-N.Y.) said he had told Manchin he did not think permitting reform would go anywhere in the current Congress. “I think it must go somewhere,” Manchin countered May 21. “We have it ready to go, and we will … see if we can move this from this committee forward on the floor.” 

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SPP Shares Concerns over EPA’s GHG Rule

SPP told its members May 20 that the EPA’s final rule curbing greenhouse gas emissions from power plants could negatively affect the nation’s ability to provide reliable service during the “swift” transition from fossil fuels to renewable energy. 

In a statement, the grid operator expressed concern about how Rule 2023-0072, finalized in April, will affect its region’s ability to maintain resource adequacy and ensure reliability. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Natural Gas Plants Exempt.) 

“SPP is concerned that limited technological and infrastructure availability and the compliance time frame will have deleterious impacts including the retirement of, or the decision not to build, thousands of MW of baseload thermal generation,” the RTO said. “If sufficient flexible thermal resources are not available to play their critical roles in SPP’s resource mix, SPP’s ability to maintain regional reliability will be directly impacted.” 

SPP noted the final rule’s emissions limits for existing coal and new gas generation are based on EPA’s finding that carbon capture and sequestration (CCS) technology is a viable “best source” of emissions reduction. It argued that CCS has not yet been “adequately demonstrated at the required capture rate” and will not be “widely available and practicable” to meet the agency’s 2032 compliance time frame. 

The grid operator also said it is concerned about the availability of gas infrastructure that will be needed for EPA’s assumption that a natural gas co-firing option would be available for existing coal units that retire before 2039. Its 2023 loss-of-load expectation study indicated that it would need as much as a 50% winter season planning reserve margin to maintain a one-in-10 LOLE, SPP said. 

“A PRM of that magnitude would require a significant amount of new capacity to be added in a short time frame,” the RTO said. “The study and its projected increase in PRM did not consider the additional at-risk generation that may retire and not be adequately replaced in a relatively short time frame resulting from the compliance time frames.” 

SPP filed comments in EPA’s rulemaking and joined with other grid operators to file joint comments. 

MMU Releases Market Report

SPP’s Market Monitoring Unit (MMU) said the return of natural gas prices to a “more normal” range and wind generation’s increasing role in the markets highlighted its annual State of the Market report for 2023. 

The MMU said gas prices dropped from an average of $5.83/MMBtu to $2.16/MMBtu at the Panhandle Eastern hub, down 63%, and were the largest contributor to a decrease in energy prices. Average day-ahead prices last year decreased 46%, from $48/MWh in 2022 to $26/MWh last year, and real-time prices were off 47%, from $44/MWh to $24/MWh. 

Wind generation continues to play an increasing role in SPP’s markets, with 33.7 GW of nameplate wind capacity producing 37% of the RTO’s generation in 2023, more than any other resource. At the same time, that has produced challenges that include the increasing variability and uncertainty of supply, out-of-market actions to ensure system reliability, higher make-whole payments and negative prices, the MMU said. 

However, the Monitor said the addition of new wind resources has slowed. Just under 1,700 MW of nameplate capacity joined the market after 1,500 MW of capacity was added in 2022. Three years ago, 3,200 MW of capacity was added. 

The Monitor made two new recommendations: Improve the uncertainty product design to ensure the procurement of adequate rampable capacity; and ensure planning, markets and operational processes appropriately consider large loads’ integration. 

The MMU will host a webinar to discuss the report at 1 p.m. June 4. Registration is open on the SPP website.

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Benefits of Revised Federal Offshore Wind Rule Analyzed

Modernized regulations for offshore wind energy development announced in April have been published in the Federal Register and will take effect July 15. 

Federal regulators say the streamlining of a regulatory regime that dates back 15 years — to well before the current wave of offshore wind development began — will save time and money as the public-private drive to site dozens of gigawatts of emissions-free generation in the ocean moves forward. (See Interior Announces Updated OSW Regs, Auction Schedule at IPF24.) 

Promised benefits such as greater flexibility, improved review processes, elimination of unneeded requirements, auction reforms and clarified oversight were welcome news to an industry struggling against economic and logistic headwinds in the United States even as it enjoys unprecedented financial and policy support. 

NetZero Insider asked three people closely involved in U.S. offshore wind development — a developer’s attorney, an advocate and a former federal regulator — what pieces of the Renewable Energy Modernization Rule they think will be most impactful and what else they think could have been included. 

Industry Veteran

Robin Main co-chairs the Environmental and Energy Group at law firm Hinckley Allen after decades practicing that field of law.

She represented developers of the nation’s first offshore wind project — Block Island Wind Farm in Rhode Island — through a lengthy and complicated permitting process.  

She subsequently represented three of the eight offshore wind projects that so far have received Bureau of Ocean Energy Management approval — South Fork Wind, Revolution Wind and Sunrise Wind. 

Robin Main, Hinckley Allen | Hinckley Allen

Main said the updated rules seem a bit random in some ways, addressing some issues and not others, but the updates are important and meaningful. 

“We made big steps forward with the so-called modernization rules. They were needed,” she said. 

Foremost, the operational life of a project is extended beyond 25 years, and the starting point for that time frame is full commercial operation, rather than first turbine spinning. 

“It’s needed because of the investments being made, the viability of the power purchase agreements, and the fact that these projects are meant to endure and certainly have an operational life beyond 25 years or so. So I was very happy to see that,” Main said. 

Also important, she said, is new flexibility on the construction and operations plan (COP) — not every design change will require a COP revision.  

“Because every time you made a change you had to send in a modified COP, then you had to send it to the states as well. So there was always this additional time in the permitting process that COP revisions were taking.” 

Changes that Main still would like to see include better coordination among the many regulatory entities that weigh in on offshore wind development. 

“I’d love BOEM to consider presumptive approvals, at least for certain aspects of projects, whether it’s cable corridors or something along those lines where developers can go in and know, ‘OK, if I meet this set of criteria or use this particular area, then it’s going to be presumptively approved,’” she said. 

New York has achieved some of this type of streamlining, Main said, and Massachusetts is trying to do as well. 

The new rule is a significant update, but there has been a continual evolution of the old rule as regulators added staff dedicated to offshore wind and as those people gained experience, Main said. 

She saw that firsthand as she progressed from Block Island to South Fork to Revolution and Sunrise. 

“And frankly, I see from a boots-on-the-ground perspective that really qualified people now want to go into that government service. They’re turned on by the fact that, you know, they’re working in energy, and whether it’s offshore wind, battery [storage] or otherwise, that this is a new frontier, and it’s much more attractive.” 

Advocating for Wind

Kelt Wilska, the offshore wind director for the Environmental League of Massachusetts, also is a regional leader for New England for Offshore Wind.  

As an advocate for a robust buildout of the emissions-free power source, he said he was happy to see the final version of the Modernization Rule. 

“It’s good for the industry, because you’re streamlining regulations, you’re clarifying things that’s going to make the development process faster, and in turn, that’s going to be a good thing for the environment and for our climate,” Wilska said. 

Kelt Wilska, Environmental League of Massachusetts | Environmental League of Massachusetts

No single aspect of the changes jumps out at him. It’s more the entirety of the changes and the benefits they will bring to the industry. 

“I think when you take all of these things together, they really add up into something special,” Wilska said. 

He said he also likes the community engagement BOEM fostered while drawing up the revisions and hopes it will continue. 

“What I want to see generally from my zoomed-out perspective as a coalition facilitator is that BOEM continues to have these frequent opportunities for public comment and participation,” Wilska said. “I think that it’s appreciated from us as advocates, and I’ve seen it appreciated by them because we can submit very technical expertise that is reflective of our very broad coalition of folks from the science space, from labor, from community organizations, from businesses. That’s all very meaningful.” 

He’s aware not everyone feels their voice is being heard, perhaps none more so than commercial fishers. But the fishing industry is being heard, he said, noting that BOEM in 2023 removed Lobster Management Area 1 from the wind energy area it was drawing up in the Gulf of Maine. 

Offshore wind will be a tough sell for some groups, but Wilska said he will not give up: “As long as I’m in this position, I’m going to keep trying to reach out to people and bring them into the conversation and see what we can do and what we can find common ground on.” 

He acknowledges the new Modernization Rule may become moot if a certain wind turbine hater is elected president. 

“Of course, I have concerns about what a potential future Trump administration could do to the regulations set forth by this current administration. There’s a lot that a future administration could do to put a hold on a lot of the progress we’ve been seeing.” 

Multiple Roles

Josh Kaplowitz has been in offshore wind for a dozen years and has seen regulatory evolution from several perspectives. 

He started off with gigs for the Department of Energy and what was then the American Wind Energy Association, then worked five years in the Office of Solicitor at the Department of Interior as counsel to BOEM; was commercial counsel at General Electric; was vice president for offshore wind at the American Clean Power Association; and now is senior counsel at law firm Locke Lord, focusing on offshore wind and other renewable energy. 

“So I’ve seen some things,” Kaplowitz said. 

The new rule is an important update, he said. It replaces a regulatory structure Interior created in the mid- to late 2000s, when there was no U.S. offshore wind industry. 

“They were furiously writing regulations, and the only model they had for offshore energy was oil and gas. And they did their best at the time to try to adapt these oil and gas regulations to this brand-new industry, or at least completely new in the United States and still pretty new in Europe,” Kaplowitz said. 

“And it quickly became clear that it didn’t always work. But actually, I will say the fact that the industry has progressed this far with rules that have essentially been unchanged for 15 years is a testament to how they didn’t do a terrible job on the front end, and they at least had the foresight to build in some flexibility through departures. They had a departure mechanism that allowed for the particularly egregious flaws in the rule to be sort of corrected on a case-by-case basis.” 

Kaplowitz said he sees some missed opportunities in the revision, such as greater certainty in permitting timelines or more structure in leasing schedules. 

“Overall, it was necessary, and it should be really helpful. Is it sufficient to make sure that the industry can accelerate and endure through changes in administration? I don’t think so. But that’s kind of the nature of the beast. What they did was very good.” 

The operational lifespan is a key change, in Kaplowitz’s view. 

Not only does the clock not start until full commercial operation, the default lifespan also is extended from 25 to 35 years, and BOEM has discretion to go even longer. 

“I think that will make a positive difference in terms of financeability of these projects. And the design life of these of these technologies has improved over time, certainly over the 15 years that BOEM’s been regulating it,” he said. 

And the revised decommissioning bond requirement — it can be spread over the project lifespan rather than posted up front — is huge, Kaplowitz said. “That is probably the most economically measurable, economically impactful provision.” 

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FERC Approves Additional Delay of ISO-NE FCA 19

FERC has approved an additional two-year delay of ISO-NE’s forward capacity auction (FCA) 19, pushing the auction to February 2028 (ER24-1710). The auction applies to the 2028/29 capacity commitment period (CCP), which begins in June 2028. 

The delay will give ISO-NE time to develop major changes to the timing and structure of its capacity auction. The RTO has proposed changing its “forward annual” auction to a “prompt seasonal” auction. This would reduce the time between the auction and the CCP from a span of over three years to just a few months, while the annual CCP would be split into distinct seasons. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

ISO-NE also plans to use the delay to continue working on its resource capacity accreditation (RCA) project, which is intended to better align capacity awards with system reliability benefits. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

“The further delay of FCA 19 provides the opportunity for substantial market efficiency improvements and reliability benefits associated with a prompt seasonal market,” ISO-NE wrote in its initial filing. 

The RTO added that implementing a prompt seasonal market at the same time as the RCA reforms would create “multiple synergies,” including the ability to take extra time to develop an optimal approach to accrediting gas resources, which has been a sticking point in the RCA stakeholder discussions. (See NEPOOL MC Backs Further Forward Capacity Auction Delay.) 

Following FERC’s May 20 approval of the delay, ISO-NE has indicated it will pause RCA discussions and will “target discussing initial scope considerations with the [Markets Committee] in July, Dane Schiro said at this month’s Markets Committee meeting.  

Regarding resource modeling and projected capacity market revenues for different resource types, “a lot of the underlying assumptions will remain the same,” said ISO spokesperson Matt Kakley. He added that some resources with varying seasonal benefits could see seasonal swings in their accreditation values, while some resources will experience minimal changes. 

The ruling will delay the auction until 2028 but does not commit the region to implementing a prompt seasonal market. FERC previously approved a one-year delay as ISO-NE and stakeholders contemplated pursuing the market changes. (See FERC Approves ISO-NE’s One-Year Delay of FCA 19.)  

Like the previous delay filing, if ISO-NE ultimately can’t pass a prompt and seasonal auction design, future auctions will proceed in 10-month increments, gradually increasing the time between the auction and the CCP until the auction returns to its current three-year-forward timeline. 

The filing was supported in comments by ISO-NE’s internal and external market monitors and the New England States Committee on Electricity and was not opposed by any groups.  

“The proposed delay will allow ISO-NE and stakeholders the time necessary to develop a prompt and seasonal capacity market framework and refine capacity accreditation methods,” FERC ruled.  

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Counterflow: Long-duration Energy Storage: Reality Check

Steve Huntoon |

Here’s the bottom line on carbon-free electricity: The proponents envision a massive portfolio of wind and solar generation. And somehow, the intermittent nature of these renewable resources will be covered by some type of storage. 

In other words, wind and solar output in excess of demand from hour to hour will charge the storage, and the storage will discharge into the grid when wind and solar output cannot meet demand. 

In theory, this can work. But as it is said, “In theory, theory and practice are the same. In practice, they are not.”1  

As I’ve discussed before, renewable resources may collectively produce little electricity for days or weeks on end.2 In 2018, there was a three-week period in PJM in which wind and solar resources averaged 10% of their combined nameplate capacity.3  

For more than three weeks in the summer of 2018, PJM’s solar and wind generation averaged only 10% of their combined nameplate capacity of 9,694 MW. | PJM

Thus, short-duration storage — one to eight hours — is basically worthless to cover a demand/supply drought that lasts for days. Short-duration storage is discharged in Day 1; there’s no net supply to recharge the storage; and that’s that. Game over. 

Enter Long-Duration Energy Storage

So that brings us to long-duration energy storage (LDES). This is now portrayed as the solution to extended droughts of wind and solar generation.  

There are many potential types of LDES.4 The most commonly cited type of LDES is iron-air (a.k.a. iron-rust or metal-air) battery storage, as typified by Form Energy, which has raised almost $1 billion for this technology.5 (My take on green hydrogen for storage or anything else is here.6 ) 

But hard data suggest iron-air technology is not ready for prime time. Practice may trump theory again. 

Poster Child: Form Energy California Project

Data points come from a California Energy Commission announcement of a $30 million grant to Form Energy for a 5-MW/500-MWh battery storage project in Mendocino County.7 This is what’s called a 100-hour storage project: 500 MWh divided by 5 MW is 100 hours. And $30 million divided by 500 MWh is $60,000/MWh.

Scoping the Challenge

As noted above, because wind/solar generation can be small for days at a time, maintaining reliability would require some way to cover net load8 for such a period. But how many days? 

A study of such renewable droughts in the U.S. came out last year.9 The study analyzed hourly data on wind output, solar output and demand by region (balancing authority). The study is complex, but the gist is to confirm the need to somehow cover multiday renewable droughts across a given region, with California the most vulnerable, with six-day droughts to be expected. The study also found that load levels are positively correlated with droughts, so low load cannot be relied on to help cover renewable droughts. 

What’s It Gonna Take?

We’ll assume needing battery storage to cover six days of severe renewable drought in California. With an average hourly load in California of 28.8 GWh,10 an average 80% supply/demand deficiency11 would be 23 GWh, which, multiplied by 24 hours and by six days, is 3,314 GWh.

What’s It Gonna Cost?

Batteries to store those 3,314 GWh at a capital cost of $60,000/MWh, based on the Form Energy project, would cost $198.8 billion, which at an annual carrying charge rate of 12%12 is $23.9 billion per year.  

This is without any cost for the energy to charge the batteries, but let’s optimistically assume the batteries can be charged with wind and solar otherwise curtailed so the energy cost would be negligible. Is there some substantial offsetting economic value of the batteries, such as energy arbitrage between high- and low-cost hours? Well, the round-trip efficiency is 35%13, which suggests limited energy arbitrage opportunity. 

What is the rate impact of this? If we divide that $23.9 billion per year by California’s annual electric usage of about 252,000 GWh per year,14 the rate impact is 9.5 cents/kwh. This would about double the generation component of California’s average electric rate and increase the already-high average retail rate by about 50%.15 Yikes! 

And this is just for the battery storage. The cost of the renewable generation itself is not included. 

Alternatives

There are other alternatives for covering California’s renewable droughts, but I’m going to focus on the existing natural gas fleet. Let’s assume we can keep 23 GW around to cover the average net load of 23 GW during a renewable drought.16 According to the California Energy Commission, the cost of retaining gas plants is between $34.26 and $43.05/kW/year.17 I’ll use the higher figure. So, the annual cost would be $990 million.  

We’ll need 3,314 GWh (calculated above) of generation to cover six days. We’ll use the National Energy Technology Laboratory’s (NETL) gas supply and other variable cost of $36.4/MWh.18 For one six-day drought, the total fuel/variable cost is $121 million. 

So, the cost to retain natural gas plants and to cover their variable costs for a six-day drought is $1.1 billion.  

Comparing Battery Storage and Retained Gas Plant Costs

Comparing the annual cost of battery storage of $23.9 billion to the annual cost of retaining gas plants of $1.1 billion means it would cost 20 times as much to employ battery storage to cover renewable droughts as to retain gas plants for that purpose. Yikes! 

And What About Greening Those Gas Plants?

This is where things get really interesting. 

What’s the additional cost to get to no (or very low) carbon using the retained natural gas plants? There are at least three options: (1) purchasing carbon offset credits for the carbon emissions from the gas plants; (2) purchasing carbon offset credits that are solely carbon capture and storage (CCS); and (3) retrofitting the gas plants with CCS facilities.  

Regarding the first option, Bloomberg forecasts carbon offset credits to cost $13/ton in 2030 and $20/ton for “high-quality” offset credits under tighter rules.19 Let’s use the higher price and convert the $20/ton to $9/MWh using an Energy Information Administration conversion rate of 0.97 pounds/kWh.20 For 3,314 GWh per year, the cost is about $30 million per year. 

The second option involves carbon offset credits that are solely CCS. Bloomberg forecasts a 2030 price for such credits of $146/ton.21 Climeworks, a developer of direct air capture plants, is forecasting a $300 to $350/ton cost in 2030 for new plants.22 Using the highest of these costs and the preceding EIA conversion rate for 3,314 GWh per year entails a cost of about $525 million per year. 

The third option is retrofitting gas plants with CCS facilities at a capital cost, according to an NETL study, of $1,212/MW23, which for 23 GW is $27.9 billion, which at an annual carrying cost rate of 12% is $3.3 billion per year.  

The Bottom Line

Now let’s compare the annual costs of long-duration battery storage with the costs of no-/low-carbon gas plant retention alternatives: 

Long-duration battery storage:  $23.9 billion 

Gas plants with carbon credits:   $1.1 billion 

Gas plants with CCS credits:        $1.6 billion 

Gas plants with CCS retrofit:       $4.4 billion 

See the difference? 

What About Future Cost Reductions in LDES?

This comparison of options is based on the cost of the Form Energy California project. There are claims of future large reductions in iron-air battery costs — let’s assume the cost per megawatt-hour goes down by two-thirds in line with Form Energy’s claimed future reduction in the kilowatt-per-year cost relative to its California project24 and a similar two-thirds reduction hypothesized in an MIT study.25 The economics remain dreadful relative to keeping gas plants around. And, of course, carbon offset and CCS retrofit costs may decline as well. 

Near-term Implications

“It is difficult to make predictions, especially about the future.”26 But it’s this sheer uncertainty that militates for keeping natural gas plants around in some form. For example, instead of decommissioning gas plants perhaps mothball them at relatively low cost. This would preserve the option of using carbon credit offsets and/or CCS retrofit in the future. 

Big Picture Implications

LDES is extremely expensive. It does not make economic sense relative to retaining natural gas plants with various carbon-abatement alternatives. 

Policymakers — legislative and regulatory — should insist on apples-to-apples comparisons of alternatives for abating carbon while maintaining reliability.

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. 

 

 

1 https://quoteinvestigator.com/2018/04/14/theory/
2 https://energy-counsel.com/wp-content/uploads/2022/11/More-Happy-Talk.pdf; https://www.energycounsel.com/docs/cue-more-pixie-dust.pdf; https://www.energy-counsel.com/docs/Cue-the-Pixie-Dust.pdf; https://www.energy-counsel.com/docs/German-La-La-Land.pdf; https://www.energy-counsel.com/docs/No-CarbCalifornia.pdf; https://energy-counsel.com/docs/Grid-Batteries-Kool-Aid-Once-More-with-Feeling-RTO-Insider-12-5-17.pdf; https://www.energy-counsel.com/docs/Battery-Storage-Drinking-the-Electric-Kool-Aid-FortnightlyJanuary-2016.pdf.
3 https://www.energy-counsel.com/docs/Cue-the-Pixie-Dust.pdf
4 https://energy.mit.edu/wp-content/uploads/2022/05/The-Future-of-Energy-Storage.pdf, pages xiii-xvii.
5 https://www.scientificamerican.com/article/rusty-batteries-could-greatly-improve-grid-energy-storage/
6 https://energy-counsel.com/wp-content/uploads/2023/12/Hydrogen-Reality.pdf
7 https://www.energy.ca.gov/news/2023-12/cec-awards-30-million-100-hour-long-duration-energy-storageproject; https://www.energy.ca.gov/sites/default/files/2023-10/CEC-500-2023-055-D.pdf. The economics of this project don’t reconcile with the description of a Form Energy project in New York said to be twice the size at less than half the cost, https://www.nyserda.ny.gov/About/Newsroom/2023-Announcements/2023-08-17-GovernorHochul-Announces-Nearly-15-Million-in-Long-Duration-Energy-Storage, although one difference is that New York limits its contribution to half the project cost, https://portal.nyserda.ny.gov/servlet/servlet.FileDownload?file=00P8z000001ocKUEAY.

8 Net load is gross load net of wind/solar generation.
9 https://www.sciencedirect.com/science/article/pii/S0960148123014659?via%3Dihub The press release summarizing the results is here, https://www.pnnl.gov/news-media/energy-droughts-wind-and-solar-can-lastnearly-week-research-shows
10 https://efiling.energy.ca.gov/GetDocument.aspx?tn=254463, page 13.
11 This means that average hourly renewable generation is covering 20% of average hourly gross load. The remaining 80% (net load) must be met by storage. This definition of severe renewable drought comes from this study, https://www.sciencedirect.com/science/article/abs/pii/S0960148118302829?via%3Dihub, page 581 and Figure 2.
12 An annual carrying charge rate reflects return of and on capital. It is currently 11.8% in PJM. https://www.pjm.com/-/media/committees-groups/committees/teac/2023/20230711/20230711-informational—market-efficiency-analysis-assumptions—july-2023.ashx
13 https://www.energy.ca.gov/sites/default/files/2023-10/CEC-500-2023-055-D.pdf, page 44.
14 https://efiling.energy.ca.gov/GetDocument.aspx?tn=254463, page 13.
15 https://www.eia.gov/outlooks/aeo/supplement/excel/suptab_54.22.xlsx, focusing on the generation sector average component around $0.10/kWh, and average total end-use prices around $0.20/kWh. Other EIA data suggest a higher current end-use price around $0.25/kWh, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_5_6_a.

16 https://www.energy.ca.gov/data-reports/energy-almanac/california-electricity-data/electric-generationcapacity-and-energy
17 https://www.energy.ca.gov/sites/default/files/2024-01/CEC-500-2024-003.pdf, page 10.
18 https://www.osti.gov/servlets/purl/1961845, Exhibit 4-6, page 26.
19 https://about.bnef.com/blog/global-carbon-market-outlook-2024/
20 https://www.eia.gov/tools/faqs/faq.php?id=74&t=11 $20/metric ton divided by 2,205 pounds/ton is $.009/pound, which is $.009/kwh or $9/MWh.
21 https://about.bnef.com/blog/global-carbon-market-outlook-2024/
22 https://www.cnn.com/2024/05/10/world/video/largest-carbon-capture-factory-opens-vause-wurzbacher-intvcnni-climate-or-business-fast
23 https://www.osti.gov/servlets/purl/1961845, Exhibit 4-5 on page 25, averaging the all-in TASC $/kw for the two 95% capture projects. Transportation and storage of the carbon is projected by DOE/NETL to cost $3.7/MWh, Table 4-6, page 26, which for 5,328,000 MWhs per year is a small cost of about $20 million per year. Another DOE retrofit study is here, https://www.energy.gov/sites/default/files/2024-04/OCED_Portfolio_Insights_CC_part_i_FINAL.pdf

24 https://www.edockets.state.mn.us/edockets/searchDocuments.do?method=showPoup&documentId={00AE3887-0000-C24C-BFC6-45EC1209A3DB}&documentTitle=20233-194396-08, Table 1, making reduction from the California project $6,000,000/MW to $1,900,000/MW (converting kW to MW).
25 https://energy.mit.edu/wp-content/uploads/2022/05/The-Future-of-Energy-Storage.pdf, page 37.
26 Dutch saying, c. 1937, https://quoteinvestigator.com/2013/10/20/no-predict/.

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Hurricane Threat to OSW Turbines Quantified

Two new reports examine storms and other obstacles facing offshore wind development in the Gulf of Mexico. 

The challenges of siting wind energy generation in the Gulf were highlighted in 2023, when the U.S. Bureau of Ocean Energy Management’s first Gulf offshore wind energy lease drew minimal interest from potential developers. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

However, the Biden administration remains keenly interested in wind energy development in the Gulf, and BOEM this year proposed a second auction, with changes intended to boost bidder interest. (See BOEM Proposes Second OSW Auction in Gulf of Mexico.) 

BOEM on May 16 announced release of “Gulf of Mexico Offshore Wind Energy Hurricane Risk Assessment” and “Assessment of Offshore Wind Energy Opportunities and Challenges in the Gulf of Mexico.”  

The two new studies are intended to inform local, state and federal strategic renewable energy planning. They are a collaboration by the National Renewable Energy Laboratory, the National Oceanic and Atmospheric Administration’s National Centers for Coastal Ocean Science, Applied Research Associates and CSS.  

One of the challenges to siting wind turbines in the Gulf of Mexico is the wind itself, which typically is weaker than in the wind energy development zones off the Atlantic and Pacific coasts — except during the Gulf region’s infamous storms, when the wind can increase to damaging velocity. 

NOAA’s historic hurricane mapping system shows 62 hurricanes hitting the Louisiana and Texas coastline in the past century, 18 of them since 2000. There also were 72 tropical storms and 37 tropical depressions in the past 100 years. 

The 30-million-acre Call Area designated by BOEM follows the coast from the Mississippi River Delta to the Mexican border. The areas designated for lease so far have been clustered south of the east Texas coast. 

“To ensure the robust design of wind turbines in the Gulf of Mexico, it is critical to understand the added risk posed by the threat of major hurricanes,” the hurricane report’s authors write in their executive summary, “because those affecting the Gulf of Mexico region have a significant potential to exceed design limits prescribed by the International Electrotechnical Commission (IEC) wind design standards.” 

A problem that immediately presented itself is the mismatch between the data used for the Saffir-Simpson hurricane scale and the IEC design criteria (in which measurements are taken for a much shorter duration at a much greater height above sea level than for Saffir-Simpson).  

Also, there are very few detailed measurements of turbulence within hurricanes over the ocean. 

IEC standards call for turbines to have a minimum 20-year lifespan and for the return period — the estimated average time between extreme wind events where they are erected — to be at least 50 years. 

The authors concluded the 70-meter-per-second 3-second gust specified as the limit for IEC Class 1A turbines would be associated with a strong Category 2 hurricane and have a return period of 20 to 45 years in the Gulf. 

The 80-meter-per-second 3-second gust specified for IEC Typhoon Class turbines would be associated with a moderate Category 3 hurricane and have a return period of 40 to 110 years. 

“This indicates that the Class 1A limit state may be nonconservative for the entire Gulf of Mexico Offshore Wind Energy area, while the Typhoon Class limit state may be adequate for the design of turbines in some regions,” the report says. 

NOAA shows 34 hurricanes rated at Category 2 or worse in the past century along the Texas-Louisiana coastline. 

A map shows suitability ratings for offshore wind energy development off the coasts of Texas and Louisiana. | BOEM

The second report raises another problematic aspect of hurricane winds: their potential to cause construction and operational risks severe enough to give insurers pause. Without insurance, a project is not financeable. 

The report says best practices for risk reduction and risk transfer are not established because there is so little operational experience with offshore wind in extreme conditions. 

However, some data are beginning to emerge from typhoons in the Taiwanese Strait, and manufacturers are developing hurricane-specific turbine designs. Successful offshore oil and gas substructure designs are informing offshore wind designs. 

The Gulf has the opposite problem on the other 364 days of the year, when there is no hurricane: The wind speed is lower than in the Atlantic or Pacific, reducing the gross capacity factor and annual energy output of a turbine while boosting its downstream wind wake effects. 

The report states there is no simple engineering solution for designing wind turbines for slower average wind speeds punctuated by dangerously high wind speeds. 

On a positive note, the report indicates the shortage of vessels and ports facing offshore wind development elsewhere in the country is less of an issue along the Gulf Coast. 

The authors identified nine ports that could support offshore wind and said those that would need upgrades would need less extensive upgrades than ports in other parts of the country. 

The authors also identified 25 potential points of interconnection with capacity of at least 230 kV but added that lengthy interconnection queues and other challenges exist in the Gulf region, as elsewhere.

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New Mexico Plots Next Steps for Day-ahead Market Decisions

As a next step in deciding which of two competing Western day-ahead markets to join, two New Mexico utilities are commissioning a study of transfer capability under different market scenarios. 

Public Service Company of New Mexico (PNM) and El Paso Electric expect to have the results of the study in July, according to New Mexico Public Regulation Commissioner Gabriel Aguilera. 

Aguilera mentioned the study during a PRC workshop May 17 on utilities’ regional market participation. The commissioner has coordinated what so far has been three workshops on the topic. 

Aguilera said he’s planning another workshop in August in which PNM and El Paso Electric can discuss “the transfer capability that exists into either market. And especially with respect to the transmission rights that they have, and other entities could have [in] either option.” 

“The connectivity is really going to be a big factor in any decision that the utilities make,” Aguilera said. 

The PRC opened a docket last year and has held workshops with the goal of developing guiding principles for utilities’ participation in a day-ahead market or RTO.

Aguilera invited entities to submit a draft guidance document for the commission to consider.  

The May 17 workshop featured presentations from CAISO on its Extended Day-Ahead Market (EDAM) and from SPP on its Markets+ offering. CAISO and SPP representatives discussed governance, market design and implementation timelines for their respective markets — similar to ground they covered in other recent presentations. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.) 

Both markets were developed with extensive stakeholder input. 

In fact, Aguilera said, participation has been so extensive it has left some stakeholders feeling overwhelmed and getting left behind in the process. But other stakeholders “have more resources and a lot at stake,” he added. 

“When you think about a stakeholder-driven process, it sounds great,” Aguilera said. “In practice, if it’s really these entities that have the most resources driving it, then it’s not really fair.” 

In particular, consumer advocates and state regulators need a larger role, he said. 

In addition to an August workshop on transfer capability, the commission might invite presentations from the West-Wide Governance Pathways Initiative and the Western Resource Adequacy Program (WRAP). The Pathways Initiative is an effort to create the governance framework for an independent market that expressly includes the state-run CAISO. 

Commissioner James Ellison said the August workshop will address a key topic. 

“The market design is important, but you’ve got to have the capacity for the regional exchanges to happen in order for the market to be valuable,” he said. 

Ellison said New Mexico is unique in having merchant transmission lines being built primarily to send wind power to California.

He said New Mexico ratepayers could benefit from California imports, which at times dip into negative pricing because of excess solar resources. 

“I do think that consideration should be given to the ability of these merchant lines to allow for that regional market participation,” Ellison said.

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CAISO Moves for Expedited Change to Soft Offer Cap

CAISO is moving quickly to win approval for a proposal to raise the soft offer cap in its market from $1,000/MWh to $2,000 to accommodate the bidding needs of battery storage and hydroelectric resources in time for operations this summer. 

The expedited proposal will be put up for a vote by the ISO’s Board of Governors and the Western Energy Imbalance Market’s Governing Body during their joint meeting May 22. 

A product of stakeholder discussions in the ISO’s Price Formation Enhancements (PFE) Working Group, the two-part proposal seeks to allow “energy-limited” resources with “intraday opportunity costs” — specifically batteries and hydro — to reflect those costs in their energy bids. 

Those opportunity costs become a factor on days when the grid is stressed by tight supplies, usually from extreme weather. Under those conditions, energy-limited resources committed to the market at the $1,000/MWh soft offer cap can find themselves dispatched at high prices occurring relatively early in the day. But because of constraints on their use once they’ve depleted their available energy, they will be unable to offer into the market later in the day in the face of even higher prices (which often signal the need for more supply to prevent grid emergencies), reducing their opportunity to earn revenues. 

“Market participants have posited that allowing these [opportunity] costs to be accurately reflected will ensure the market can effectively and efficiently manage the dispatch of these resources,” CAISO’s proposal says. 

The proposal is tied to the ISO’s rules stemming from FERC Order 831, which was issued in November 2016. That order required RTOs/ISOs to subject the bids of an energy resource in their markets to the higher of either a soft offer cap of $1,000/MWh or a cost-based offer already verified by the market operator, which can exceed the soft cap. In the CAISO market, the ISO-recognized offer level for a resource is referred to as the resource’s default energy bid (DEB). 

To address concerns about the potential for runaway prices because of market power, Order 831 also directed RTOs/ISOs to set a hard cap of $2,000/MWh for energy offers in calculating LMPs. 

‘Uncap the DEB’

CAISO’s proposal explains that, to comply with Order 831, the ISO developed a reference level change request (RLCR) process to verify that a resource’s costs exceed the soft offer cap, allowing a resource to update its DEB to reflect its full costs for serving incremental demand. 

But the RLCR process “was tailored toward gas resources that faced discrepancies between their actual fuel costs and the costs that CAISO’s market systems used to calculate their DEB” and “was designed to validate requested DEB adjustments, using a reference based on fuel costs, in response to changing fuel costs.” 

Energy storage and hydro resources cannot use the RLCR process “to adjust their DEBs in response to intraday opportunity costs because the ISO does not have rules to determine a reasonable cost expectation upon which to base an intraday opportunity cost adjustment request,” the proposal says. “Without the ability to use the automated RLCR process, hydro and storage resources cannot request DEB adjustments or bid above the soft offer cap when opportunity costs materialize in real time.” 

To remedy that issue, the first part of the proposal (section 4.1) calls for the cap on all energy bids — including those from natural gas-fired resources — to be raised from $1,000/MWh to $2,000. 

“This proposal would ‘uncap the DEB’ for all resources” in both the day-ahead and real-time markets, CAISO wrote. “In particular, this would allow hydro resources to bid up to a value that reflects the opportunity costs already defined in their DEBs, even when those costs exceed $1,000/MWh.” 

Because the DEB reflects a resource’s “verifiable” cost-based offer, the proposal would comply with Order 831 rules requiring such offers to be capped at $2,000/MWh, CAISO said. The plan represents “a process change, not a value change,” because eliminating the $1,000/MWh from the DEB calculation “does not change the basis for calculating marginal reference costs accepted” as the DEB, as outlined in the ISO’s tariff, it said. 

The ISO also attempts to provide assurance that the change won’t mean gas-fired resources will have a free pass to increase their DEBs. 

“This proposal would not change the resource-specific parameters defined by any resource’s DEB calculation, but offers value to resources for whom the automated RLCR process is cumbersome or unusable for validating costs above $1,000/MWh,” the proposal says. 

Rules for Storage

But the proposal also explains that the proposed bidding changes cannot apply to battery storage resources in the near term because the technological changes needed to accommodate them cannot be implemented by this summer. 

For that reason, CAISO proposes a second provision (section 4.2) that offers an “interim solution” by modifying market rules to provide storage resources in both the ISO and the WEIM to bid with more flexibility. 

“The additional flexibility allows these resources to reflect intraday opportunity costs not fully captured by the existing storage DEB, and allows storage resources to unlock the benefit of the uncapped DEB value as a cushion in the event of market power mitigation,” the proposal says. 

Under the plan, instead of using a storage resource’s uncapped DEB to formulate a bid, the proposal calls for using the market’s maximum import bid price (MIBP) — set by bilateral market prices outside CAISO — as a proxy for the resource’s “verifiable opportunity costs.” 

“The ISO proposes to allow storage resources to bid up to the higher of the MIBP’s fourth-highest calculated hourly value and the highest cost-verified bid when either of those values rise above $1,000/MWh,” allowing those resources to manage their state of charge (SOC) through economic bids. 

“Functionally, this proposal ensures four hours of SOC, which correlates to the typical sizing of the existing battery fleet, is available for use across net-peak hours, aligns with the day-ahead schedules and accurately values the storage resources’ opportunity costs,” the proposal says. 

MSC Endorses

CAISO’s Market Surveillance Committee endorsed the proposal in a 3-0 vote during its meeting May 15.  

Committee members said that, for them, concerns about reliability trumped those about market power. 

“I would say on balance, we’re more worried about the depletion of storage than we are about the questions of system market power at this point,” said James Bushnell, professor in the Department of Economics at the University of California, Davis. 

Kyle Navis, a senior analyst with the California Public Utilities Commission’s Public Advocates Office, expressed concern about letting batteries bid above the cap and warned the proposal was advancing too quickly. 

“I want to say that Cal Advocates agrees that the problem statement guiding this initiative is a valid concern that needs to be addressed,” Navis said. “At this particular point, our fundamental overarching concern is that the expedited interim solution for summer 2024 has been too rushed and is not ready for adoption and creates significant cost risks.” 

Michele Kito, CPUC regulatory analyst, expressed myriad concerns with the proposal, including a contention that the new bid calculation used for storage resources would represent a price based on a “thinly traded” bilateral market rather than a true opportunity cost for those resources.