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November 30, 2024

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NYISO Proposes Changes to Special-case Resource Program

NYISO is proposing to increase the required duration of special-case resources’ load curtailment from four hours to six following a survey showing stakeholder support as part of the ISO’s Engaging the Demand Side initiative.

SCRs are demand-side resources connected to a load that is capable of being interrupted at NYISO’s direction, including on-site solar. These resources may also have a local generator that is behind the meter and rated at 100 kW or higher that can be used to reduce load. They are activated when operating reserves are forecasted to be short; when there are actual operating reserve deficiencies; or in case of another emergency to balance load and generation. SCRs from aggregate resources must be within the same zone.

Currently NYISO requires SCRs to curtail load for at least four consecutive hours. Increasing the requirement to six hours would “provide the opportunity for SCRs to earn additional revenue for load reduction and enhance NYISO grid operators’ ability to balance supply and demand,” Michael Ferrari, ISO market design specialist, told the ICAP Working Group on July 15.

“Multiple Intervenors supports this particular change, and that support is really driven by the vast chasm of compensation between four- and six-hour resources with respect to NYISO’s capacity accreditation initiative,” said Mike Mager, an attorney for Multiple Intervenors, a large energy customer organization. “I will note, however, that that’s not unanimous.”

Some stakeholders asked whether NYISO would consider creating SCR categories with different durations.

“It is certainly easiest to have a single class for SCR, where it is one duration, and resources can just be dispatched by zone,” Ferrari said. “It is certainly more burdensome for two different classes of SCRs. But given the feedback on the desire for more flexibility, it’s something I think we can consider.”

“I appreciate that a one-size-fits-all approach is easiest for you,” said Kevin Lang, of law firm Couch White. “I would just note that for your suppliers, you don’t have one-size-fits-all approaches.”

“It’s not so much that it’s burdensome,” explained Zach Smith, vice president of system and resource planning for NYISO. “It’s remembering that this is a manually activated program, which is very different from every other supplier.”

Ferrari told the working group that NYISO is also considering shortening the activation notice period for the SCR down from 21 hours. The final, shorter duration would still be roughly a day-ahead notice, but the final time has not been decided.

“On a preliminary basis, the feedback we’ve gotten from our members” is they prefer “a fixed-time approach sometime comfortably prior to the close of business the day before,” Mager said. “By 1 p.m. or 2 p.m., they would know whether the call was happening or not.”

One stakeholder reminded NYISO that certain engineers and professionals that manage building and industrial infrastructure would not be available after 3 p.m. because their days start much earlier than the traditional “start of business.”

NYISO is also proposing changing the method for determining SCRs’ baseline load values from average coincident load (ACL) to customer baseline load (CBL). Ferrari said that CBL would allow the ISO and market participants to more accurately look at the energy available to reduce load. Some stakeholders noted that this would be more difficult to calculate and potentially be confusing for operators.

“I would note that all of the changes being proposed have the effect of seemingly making performance more difficult or challenging for participants,” Mager said.

Others noted that the CBL was already being used in the installed reserve margin study to estimate the amount of relief from using an SCR.

NYISO plans to deploy these revisions to the SCR program in the 2026/27 capability year with possible phased implementation. Several stakeholders expressed disappointment that the six-hour duration could not be deployed sooner.

“We certainly understand the request and the desire and the disappointment that this cannot be made sooner,” Smith said. He explained that to implement the change for 2025/26, a software update would be needed by February. “We did not ask to have software development as part of the work for this year, and the two months that we have to deploy this is insufficient for even just” a change of two hours.

Smith said that NYISO would continue to evaluate whether that could be accelerated.

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NEPOOL Reliability Committee Briefs: July 16, 2024

New Data Collection Standards

The NEPOOL Reliability Committee (RC) voted July 16 to support new data collection standards for distributed energy resources (DERs), intended to aid the RTO in both real-time operations and longer-term planning studies.

While ISO-NE currently collects data using voluntary submissions, the new standards would require data submissions from distribution providers and transmission owners related to DER size, location and operating characteristics, said Dan Schwarting of ISO-NE.

“Uniformity in data submission will lead to better accuracy of load forecasting and studies at ISO-NE,” Schwarting said. The proposal now heads to the NEPOOL Participants Committee.

Affected System Operator Study Coordination

Brad Marszalkowski of ISO-NE outlined proposed tariff changes to coordinate affected system operator (ASO) studies with the new cluster study interconnection process, which was mandated by FERC Order 2023. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.)

ASO studies are under the jurisdiction of the states and assess the impact of distributed generation projects on the transmission system and broader power grid. They are performed by the relevant transmission owner.

“ASO studies will have to coordinate with and respect ISO Cluster Studies,” Marszalkowski said. “This will naturally establish windows for the start and completion of ASO studies.”

Marszalkowski said the new ASO process would create a “state project submission window” that coincides with the ISO-NE cluster request window. ASO studies corresponding to each window would occur simultaneously with ISO-NE cluster studies. The studies would be required to account for ISO-NE interconnection requests and updated ISO-NE study information.

“ISO-NE will no longer consider one-at-a-time project additions,” Marszalkowski noted. “Determinations will be made solely based on the total aggregate of all projects submitted during the submission windows that are electrically close based on the screening criteria.”

Order 881 Changes

ISO-NE also discussed planning procedure changes associated with FERC Order 881, which requires transmission providers to adopt ambient adjusted line ratings for near-term transmission service requests and seasonal ratings for longer-term requests.

The commission accepted ISO-NE’s compliance proposal in 2023, subject to an additional filing by November 2024 to specify “timelines for calculating or submitting AARs.” The compliance will take effect in July 2025. (ER22-2357, see Order 881 Timelines Need Explaining, FERC Says.)

Michael Drzewianowski of ISO-NE said Order 881 compliance requires changes to the RTO’s Planning Procedure 7 (PP7), which “provides the general assumptions to be used in the calculation of facility ratings.”

For seasonal ratings, ISO-NE plans to use 12 seasons corresponding to each month, said Drzewianowski, outlining the ambient temperatures the RTO will use for each month under normal and emergency conditions.

To account for changing seasonal load shapes, ISO-NE plans to shift to a long-time emergency (LTE) rating period of four hours across the entire year, instead of the current LTE ratings of four hours in the winter and 12 hours in the summer.

Drzewianowski said ISO-NE will review stakeholder comments and changes to the PP7 appendices at the August RC meeting, targeting a vote in September.

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ISO-NE Planning Advisory Committee Briefs: July 17, 2024

Following its increase of the transfer limits on three interfaces in Maine, ISO-NE has increased the capacity import capability of the New Brunswick-New England (NB-NE) interface from 700 MW to 980 MW, Alex Rost of ISO-NE told its Planning Advisory Committee. 

ISO-NE announced the Maine transfer limit increases to the PAC in June. (See ISO-NE PAC Briefs: June 20, 2024.) The increases were the result of changes to how the RTO calculates the limits, which now are “based solely on ‘design contingencies’ — loss of transmission lines, transformers, etc.,” ISO-NE said. 

Capacity historically has been constrained in parts of Maine because of the interface transfer limits and existing capacity resources above the Maine interfaces, Rost said, adding that “the amount of capacity than can be transferred over the NB-NE interface has been limited to 700 MW out of a possible 1,000 MW for many years.” 

He noted that “proposed new capacity resources north of the Orrington-South interface have been unable to qualify for FCAs [forward capacity auctions] for many years,” and new resources have faced similar problems above the Surowiec-South interface since 2016. 

Responding to stakeholder questions, Rost said the import capability increase from New Brunswick likely means no new headroom will be made available for new capacity resources above these interfaces. 

“I’m not going to give official overlapping impact analysis answers today, … but if you walk through the analyses and steps that we went through and you crunch the numbers, that would indicate that there is no headroom,” Rost said.  

Abigail Krich of Boreas Renewables expressed concern that increasing the import capability from New Brunswick but not increasing the limits on domestic capacity could lead to the increased transfer capabilities being “reserved and underused.” 

When transfer limits are increased, “we reserve those for imports, instead of for domestic generation qualified to participate in the capacity market,” Krich said. “We reserve them for imports regardless of whether they actually get used for imports. We often see that the New Brunswick interface, historically, even at 700 MW, has not been fully subscribed. 

“This is something we should all be thinking about: How we can better utilize this transfer capability to ensure we’re getting the most out of it?” 

Rost also noted that ISO-NE likely will reassess the internal transfer limits once the New England Clean Energy Connect transmission line is in service to account for system upgrades associated with the line. 

Eversource Asset Condition Project Cost Increase

Also at the PAC, Chris Soderman of Eversource presented a cost and scope increase of an asset condition project in Connecticut. The project now includes the replacement of 22 structures and is projected to cost $32.2 million, compared to the initial estimate of $11.6 million. The project has an estimated in-service date of the fourth quarter of 2025. 

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Utilities Seek Rehearing in FERC Interconnection Funding Proceedings

A group of utilities have filed for rehearing of a show cause order FERC issued last month that could change the practice of who pays for interconnection lines at four ISO/RTOs. (See FERC Issues Show-cause Order on TO Self-Funding in 4 RTOs.) 

The commission asked ISO-NE, MISO, PJM and SPP to explain why their tariffs that give utilities the first shot at paying for the transmission upgrades required by interconnecting generators are just and reasonable, or to submit changes. 

Ameren Services, American Transmission Co., Duke Energy, Exelon, Northern Indiana Public Service Co. and Xcel Energy Services filed for rehearing of the show cause order this week. Ameren won a lawsuit involving MISO that started the practice back in 2018, but the District of Columbia Circuit Court of Appeals directed the commission to better explain its reasoning in 2022 after it had spread to the three other markets. (See FERC Must Clarify MISO Transmission Funding Decision, DC Circuit Finds.) 

The 2018 decision from the same circuit court found that revoking transmission owners’ right to self-fund network upgrades for interconnection and earn a right of return raised serious “statutory and constitutional concerns” due to compelling generator-funded upgrades on utility business models. 

“The commission has now decided to take on those serious constitutional and statutory questions — and potentially take the historic step of compelling the construction, ownership and operation of interstate transmission facilities by private entities with no opportunity to earn a return — all on the unproven premise that doing so will actually save consumers money,” the rehearing request said. “The show cause order is short-sighted and unwarranted. Investor-owned utilities investing private capital in exchange for a reasonable return is one of the most basic tenets of the century-old regulatory compact between government and the utility industry.” 

The constitutional issues come from the Fifth Amendment, which bars the government from taking private property for public use without compensation. Under the Federal Power Act, that has been interpreted to mean FERC cannot impose “confiscatory rates,” which means utilities need to be able to earn a reasonable return on the value of property at the time it is being used to render service. 

“It cannot be lawful to compel the construction, ownership and operation of utility-owned assets with no opportunity to earn any return,” the rehearing request said. “On this basis, the proposal in the show cause order is per se unconstitutional.” 

FERC suggested the interconnection upgrades can be treated as “nonprofit appendages without jeopardizing total return,” but the utilities argued it lacks the authority to eliminate equity returns from an entire class of rates represented by a major driver of new transmission investment. The utilities argued the decision could discourage much-needed investment in transmission expansion. 

The commission has run multiple proceedings that led to the rules at issue, while the D.C. Circuit’s 2022 ruling only required a better explanation as to why “generators’ concerns about potential discrimination did not outweigh the transmission owners’ enterprise-risk concerns.” 

The show cause order goes further and reopens the potential for discrimination in what appears to be an effort to “backfill the record that never materialized” in the proceedings leading to the currently effective rules across the four markets, the request said. 

The dispute started in MISO with FERC proceedings stretching back to 2011 with multiple proceedings that wound up before the D.C. Circuit with the court vacating decisions empowering generators to override a transmission owner’s self-funding choice. 

The court concluded the commission had “distorted and dismissed” the transmission owners’ fundamental argument that FERC’s orders would require transmission owners “to act, at least in part, as a nonprofit business,” and constituted an “attack on their very business model,” creating a risk of deterring “new capital investment,” the rehearing request said. 

That 2018 decision found it was “at least uncertain” FERC would reach the same conclusion on remand after addressing the deficiencies identified by the court. FERC sided with the transmission owners on the remand order. American Clean Power Association then filed a lawsuit that led to the 2022 decision, which FERC did not deal with until the show cause orders issued in June. 

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DOE, AAI Reports: VGI Critical to Managing New EV Power Demand

Vehicle-to-grid integration (VGI) is about more than connecting electric vehicles to the grid, say reports from the U.S. Department of Energy and the Alliance for Automotive Innovation, both released July 16.  

Rather, it represents a convergence of the automotive and electric industries in ways that could provide benefits for the grid, utilities, EV drivers, all utility customers and, in the big picture, society in general.  

At its most basic, VGI is the use of electric vehicle batteries, connected to EV chargers, as grid resources, either through managing when and at what pace they charge or tapping EV batteries for grid support or backup at times of peak demand or in emergencies.  

The two reports are complementary, with DOE’s “The Future of Vehicle Grid Integration” laying out a vision for VGI development by 2030, while the AAI report provides lists of recommendations focused on rate design and the kinds of technology that will be needed for consumer, utility and regulatory buy-in. 

DOE sees huge potential for VGI, with “millions of electric vehicles, charging at home and work, at charging depots and along the [highways] … integrated with the electricity system in a way that supports affordable and reliable charging for drivers and enables a reliable, resilient, affordable and decarbonized electric grid for all utility customers.” 

VGI can “seamlessly [align] the grid’s physical infrastructure and operational structure, regulatory frameworks and market design with customer charging behaviors to create a symbiotic relationship that benefits everyone regardless of EV ownership,” the report says. 

AAI’s definitions of success are more specific and targeted at building a solid business case for VGI. For EV drivers, VGI should deliver no-compromise mobility; convenient, reliable and affordable charging; and compensation for grid services, while utility customers will get a more efficient and modern grid that enhances system reliability and resilience and delivers economic and environmental benefits. 

Recommendations for utilities include adoption of time-of-use rates for EV charging and allowing EVs to participate in demand response programs. 

The overlap between the two reports is their recognition of the complexity of the work ahead to achieve their goals and the need for broad-based collaboration between utilities, automakers, regulators, EV charging firms and software developers, and local officials and community groups. 

Both also call for the development of standards and codes, with AAI more focused on data accuracy and technical interoperability, and DOE calling for “cyber-informed engineering” for EVs, charging equipment and the grid to minimize physical and cyber threats. 

What is also implicit in both reports is a shared sense that as more EVs hit the road across the U.S., VGI will be critical to managing their increased electricity demand, and best practices and information sharing will be needed to move beyond a recurring pattern of utility pilot programs to fuller system integration. 

DOE’s Big Picture

The DOE report was developed by the department’s EVGrid Assist initiative, which is itself a cross-industry group. The report notes it is intended to set goals for an ideal VGI environment and that a second report with specific strategies will be forthcoming.  

At the same time, it provides a framework for why VGI is important and specific pillars that could form a core for successful and equitable deployment of VGI.  

The report argues that VGI increases the use of grid infrastructure, cutting system costs, while helping to hold the line on electricity rates and put more clean energy online. EV owners can take advantage of more cost-effective charging, which lowers their total cost of ownership.  

VGI programs could also serve as a model for tapping other distributed energy resources for grid support and flexibility, the report says. 

Pillars for successful VGI deployment will include recognizing the “universal value” VGI provides to all utility customers and promoting a “right-sized” grid in which managed charging programs could cut peak loads and provide system flexibility. “Better use of grid assets reduces the risk of overbuilding,” the report says. 

For example, the report calls on utilities to provide “clear information about upgrade costs, capacity availability and load service request processes [to] help developers and site owners identify cost-effective charging locations where capacity is available.” 

The report’s other pillars focus on developing standards and codes, ensuring system security and providing customers with “a wide range of products and services to accomplish their charging needs,” as well as compensation for the services they provide. 

Both DOE and AAI recommend that VGI programs offer “value stacking,” allowing EV owners to get paid for different services their EVs might provide. 

Telematics and Bidirectional Charging

Incentivizing VGI through various rate designs is a priority in the AAI report. Utilities and regulators could support the deployment of DC fast chargers by adopting commercial and industrial rates that “ensure the … viability of fleet electrification and DCFC stations in the early stages of operations and in lightly trafficked areas.”  

Chargers in remote areas may not, at first, get enough use to cover utility demand charges and make the chargers financially viable, the report says. Possible solutions could include “temporary demand charge holidays … offsetting the demand charge with declining short-term subsidies and replacing the demand charge with a kW-based subscription fee.” 

For fleet electrification, another option is automated load management, a system that manages demand across more than one EV charger and can cut costs for the installation and operation of charging equipment, the report says. 

On the residential side, AAI pushes for a “prompt transition” from pilot programs offering time-of-use rates or managed charging to mass market initiatives, which will be “crucial to achieving cost-effective VGI as EV adoption accelerates.” The report also urges utilities and automakers to work together on wider consumer education programs to ensure EV owners are aware of and can easily sign up for such programs. 

AAI also points to telematics ― the integration of telecommunications and computer data ― as a key tool for advancing the benefits of managed charging. 

“Telematics-based managed charging programs integrate vehicle and utility data to optimize the timing of charging, thereby enhancing the value of an EV as a grid resource,” the report says. 

“By factoring the state of charge into the optimization algorithm, telematics-based managed charging systems can determine how long it will take to replenish the battery and therefore how much latitude there is to modulate charging to shift load and provide grid services,” it says. 

Deploying bidirectional charging at commercial scale is another way EVs can be integrated with the grid. By allowing EVs to charge from or discharge to the grid, bidirectional charging essentially turns EVs into mobile batteries that can provide “frequency regulation, spinning reserves and load shifting,” the report says. “Their ability to charge and discharge multiple times while plugged in significantly augments their value relative to standard EVs.” 

However, not all EVs currently on the market have bidirectional charging, which the AAI report says is costly to build into the vehicles, and incentives may be needed to compensate fleet operators for the added expense.  

The bottom line is that utilities, RTOs and regulators should enact policies and programs to compensate EV owners who send power to the grid, the report says. A Pacific Gas and Electric pilot program for EV commercial fleets provides incentives to offset equipment costs and uses day-ahead hourly pricing to encourage fleet operators to put power from their EV batteries back on the grid during times of peak demand. 

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Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation

Clean energy nonprofits continued trying to persuade Entergy and MISO South state regulators to embrace a broader view of cost allocation for an upcoming long-range transmission plan (LRTP) portfolio the RTO intends for the subregion.

The Sustainable FERC Project and the Southern Renewable Energy Association (SREA) took turns during an Entergy Regional State Committee (E-RSC) teleconference July 12 attempting to convince the company and its regulators to open their recommended allocation method to more transmission benefits.

Lauren Azar, a consultant for the Sustainable FERC Project, said if MISO South doesn’t create a functioning cost allocation for regional lines, the South will continue to exclusively build expensive local projects “that are bubbling up in the [integrated resource planning] process.”

“Local projects cannot cost-effectively replace regional projects, but regional projects may cost effectively replace local projects,” Azar told the E-RSC.

In early February, the E-RSC Working Group unveiled a preferred allocation for the upcoming LRTP portfolio of projects that will focus on MISO South. It involves assigning 90% of costs based on adjusted production cost savings and avoided reliability projects; the remaining 10% will be charged to new generation that interconnects in MISO South based on a flow-based methodology. (See Entergy States Debut Long-range Tx Cost Allocation Proposal, MISO Members Unconvinced.) Additionally, the E-RSC wants costs of transmission projects designed to further decarbonization goals solely assigned to jurisdictions that proposed those targets.

The Entergy states want the allocation assigned to upcoming LRTP projects in MISO South. By comparison, MISO Midwest is using a simpler, 100% postage stamp allocation to load for the same class of projects. Entergy states have been adamant that they won’t support any postage stamp allocation component for the third LRTP portfolio.

The E-RSC has said its allocation method would dole out costs as specifically as possible based on cost-causation and beneficiaries-pay principles. MISO, on the other hand, has proposed to allocate 50% of South LRTP projects to the subregion using the load-ratio postage stamp rate, and 50% to the smaller zones where projects are located. The E-RSC has publicly opposed the plan. (See Entergy Regulators Mount Challenge to MISO South Cost Allocation.)

Azar said MISO South’s local projects cannot account for the “economies of scope and scale” that regional, interstate transmission projects can capture. She cautioned that the South’s trend of relying on utilities’ IRPs for transmission planning instead of turning to MISO for comprehensive, cost-shared solutions will cost customers money in the long run.

Because regional lines benefit so many, there are many parties to “bicker” over how the costs of lines should be divided, she said. “Literally the flows on the system are changing minute-by-minute.”

Azar said the E-RSC seems to be hamstringing itself by maintaining an overly restrictive benefits philosophy that prevents it from considering other real benefits of transmission.

Arkansas Public Service Commission consultant Keith Berry disagreed that the E-RSC’s cost allocation principles are boxing its working group in from formulating adequate benefit metrics.

But Azar said the E-RSC Working Group has so far been able to come up with just two benefit metrics that almost certainly will fail to meet FERC’s standard that costs be portioned out roughly commensurate with benefits.

“You’re going to have to come up with different ways to meet that legal standard,” she said.

MISO Midwest’s 100% postage stamp allocation based on a load ratio share is often misunderstood as an “everybody pays the same rate” allocation when it’s really a rate based on grid usage, Azar said.

SREA Executive Director Simon Mahan said MISO South’s failure to settle on a cost allocation direction with the RTO may have kept it from reaping the benefits of major transmission projects.

“It’s my view that if we had a cost allocation for MISO South in place … we might have been able to move faster on the planning side,” he said.

Mahan also said FERC’s recently authorized Order 1920 is essential for MISO South states, whose IRPs are largely silent on long-term, regional transmission.

Mahan said Order 1920 is “based heavily on what MISO already does” for MISO Midwest. He said MISO South can use FERC’s planning directives “to help fill a gap” that exists in the South’s long-term transmission planning.

Though Order 1920 prescribes long-term planning on a five-year cycle, MISO South should undergo regional planning every three years, Mahan continued. That would prevent the yearslong “drought” MISO Midwest experienced between its last market efficiency project and the introduction of the long-term transmission portfolios, he said.

“You can go back at MISO’s old transmission planning futures and see how drastically things have changed,” Mahan said in support of speedier planning cycles.

Six years elapsed between MISO’s last successful market efficiency project — the $156 million, 345-kV Huntley-Wilmarth line in southern Minnesota — and its 2022 approval of its first, $10 billion LRTP for MISO Midwest.

Mahan pointed out that MISO South has never hosted a market efficiency project, and MISO’s only attempt at one in the South proved unsuccessful.

MISO canceled the $130 million, 500-kV Hartburg-Sabine Junction project in East Texas in 2022, five years after recommending it. At the time, Texas’ ultimately unconstitutional right-of-first-refusal law introduced questions over who could construct the line. Entergy in the meantime built the 993-MW Montgomery County Power Station in southeast Texas, and made plans for the 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station by 2026, rendering the line unnecessary, according to MISO’s analyses.

Since then, Entergy has proposed billions in transmission projects to serve reliability needs. MISO South accounted for nearly half the cost of MISO’s record-breaking, $9.4 billion Transmission Expansion Plan, including a $1.1 billion, 150-mile 500-kV line and substation project Entergy proposed for southeast Texas.

Bill Booth, a consultant to the Mississippi Public Service Commission, pushed back on the notion that MISO South’s nonexistent allocation has put a drag on MISO planning. He argued that an unfinished cost allocation couldn’t have been holding up regional transmission because MISO hasn’t begun planning the third LRTP portfolio.

Booth said it seemed like Mahan was trying to argue that the South should be more like the Midwest. He also said MISO South is in the construction phase of several million dollars worth of transmission investment.

But Mahan said those investments are set to produce only local lines that don’t cross state lines.

Mahan made the case there are parallels to be drawn between MISO South and Midwest. He said that while the South doesn’t have the impending coal retirements that the Midwest is staring down, it does have aging, legacy gas units. He also said the South boasts utilities with zero-carbon goals, corporate interest in load growth, escalating extreme weather events and growing renewable fleets.

“While we’re not the same as the North, there are a lot of solutions where transmission can help,” Mahan said, adding that the South region is woefully behind on attending to its regional system.

“There are things that beg a larger planning than what we’ve been engaging in the past decade or so,” he said. “We do need to fill in this gap about what we do on long-range transmission planning.”

Azar warned Entergy and regulators against crafting an allocation with FERC’s Order 1000 in mind. By the time MISO pulls together South LRTP projects — likely in 2026 — Azar said Order 1920 will be the prevailing transmission rule.

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Reports Examine Economics of Clean Hydrogen

Two new reports look at the evolving economics and technologies of clean hydrogen as its potential role in the clean energy transition is debated. 

Researchers at the National Renewable Energy Laboratory (NREL) conclude that using electricity from offshore wind farms to produce clean hydrogen may make economic sense, possibly lowering the cost of generation to below $2 per kilogram.  

This is well above the $1/kg target set by the federal government but well below current cost of production, and possibly low enough to make it cost-competitive in some applications. 

An analysis by the Clean Air Task Force (CATF), meanwhile, concludes that use of clean hydrogen for power generation would be a costly and inefficient decarbonization strategy and that hydrogen would best be prioritized as a means of decarbonizing heavy transportation and industry. 

This analysis also found that using hydrogen as a form of energy storage could have some applications but likely would be less cost effective than strategies that minimize the need for long-duration energy storage, such as geothermal or nuclear. 

The Biden administration has prioritized the development of clean hydrogen. It launched the Hydrogen Shot in 2021 to lower the cost from $5 to $1 per kilogram by 2031, and it designated seven regional hydrogen hubs in 2023. (See DOE Designates Seven Regional Hydrogen Hubs and DOE Hydrogen Shot Aims to Build US Supply Chain for Global Markets.) 

But the rules for hydrogen tax credits it proposed seven months ago have been mired in controversy, decried as too strict by some in the energy sector and not strict enough by some clean energy advocates. (See Biden Admin. Releases Proposed Rules for Hydrogen Tax Credits.) A similar reception greeted the announcement of the hubs. (See Hydrogen Hub Announcement Draws Praise and Scorn.) 

Both sides have been pushing since then to influence the final rule-making. The outcome will help determine the net environmental benefits of “green” clean hydrogen and what it costs to produce. 

Offshore Wind

The NREL researchers’ article — “Potential for large-scale deployment of offshore wind-to-hydrogen systems in the United States” — was published in Journal of Physics: Conference Series and was announced July 11.  

Their findings indicate the economics of producing hydrogen with offshore wind electricity would be most favorable in areas where the water is relatively shallow and the wind is relatively strong.  

The levelized cost of hydrogen, which looks at the entirety of the wind, hydrogen and transmission infrastructure, would be lowest in the New York Bight and second lowest in the Gulf of Mexico, they determined. 

The researchers looked at two system configurations that have been considered: a traditional setup with power exported to onshore electrolyzers that produce hydrogen from freshwater and a setup in which electrolyzers at sea produce hydrogen from desalinated seawater and send it ashore via a pipeline. 

The technical feasibility of the offshore hydrogen production scenario is uncertain, the researchers said, as it would require integration of large amounts of equipment on a 250-by-250-meter sea platform. 

In a news release, lead author Kaitlin Brunik, an NREL hybrid systems research engineer, said: “Both offshore wind and clean hydrogen production are technologies that are rapidly evolving and, when combined, have the potential to generate and store a lot of renewable energy and decarbonize sectors that are hard to electrify. Continued investment and research on system- and plant-level design and optimization could spur further technology progress and cost reductions for these systems.” 

Production Economics

CATF announced its report, “Hydrogen in the Power Sector: Limited Prospects in a Decarbonized Electric Grid,” on July 4. 

It points out the challenge of green hydrogen — to produce it in a way that does not cancel out its environmental benefits as a non-carbon fuel. 

It also flags a fundamental handicap of present-day technology: It expends three-quarters of the energy potential of clean hydrogen in the process of making it. So, four units of clean energy that could be used to decarbonize the grid instead are used to create one unit of clean hydrogen.  

The analysis pokes holes in the concept of using hydrogen as a power generation fuel, stating that substantial investments in storage and transmission would be needed; creating green hydrogen with electricity from renewable sources would divert that power from other decarbonization uses; producing hydrogen from natural gas with carbon capture creates significant upstream emissions associated with producing and transporting the natural gas; and the levelized cost of electrolytic hydrogen as a storage medium exceeds other options, such as pumped storage hydropower and batteries. 

It adds, however, that present-day batteries are of limited duration and that hydrogen is at present one of the few technically feasible methods to convert large amounts of electricity into energy that can be stored for months. 

In a news release, CATF Hydrogen Technology Director Ghassan Wakim said: “Interest in using hydrogen to decarbonize power systems has skyrocketed, specifically as a perceived ‘clean’ replacement for natural gas power plants. The superficial logic is simple: Replace a polluting fuel with one that doesn’t emit carbon dioxide. Unfortunately, the inefficiency of hydrogen production means that it either amplifies upstream natural gas emissions or diverts clean electricity that could directly decarbonize the grid instead. After a realistic assessment of clean hydrogen’s potential role in power sector decarbonization, this report finds that clean hydrogen should be prioritized for decarbonizing heavy transportation and industry, not for electricity generation.” 

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CPUC Works to Revamp Tx Permitting Rules

California regulators are overhauling rules regarding the permitting of electric transmission projects, and one proposal suggests creating a shortcut for projects already approved in a CAISO transmission plan.

The California Public Utilities Commission is updating General Order 131-D, which contains rules for the permitting of transmission and distribution lines, substations and generation facilities in the state. The goal of the update is to make the permitting process more efficient and consistent.

GO 131 was originally adopted in 1970. The most recent version, GO 131-D, was approved in 1994 and modified in 1995.

Since then, “there have been significant changes in both the physical configuration of the electric grid and the market structure for electricity in California,” commissioners said in an order instituting rulemaking for GO 131-D.

In addition, Senate Bill 529 of 2022 directed the CPUC to update the general order to streamline the approval process for extensions, expansions or upgrades to existing transmission facilities.

Under GO 131-D, transmission projects of 200 kV or more need a Certificate of Public Convenience and Necessity (CPCN), whereas projects between 50 and 200 kV must obtain a Permit to Construct (PTC), which involves a less complex approval process.

But SB 529 changed the requirement for a CPCN for transmission expansion projects. Those projects now may proceed with the simpler PTC, even if they’re 200 kV or greater.

In Phase 1 of the proceeding, the CPUC updated GO 131-D to be consistent with SB 529.

An order incorporating the changes was approved and took effect in December, ahead of the Jan. 1, 2024, deadline set by SB 529.

Phase 2 Proposals

The proceeding has now moved into its second and final phase, in which additional changes to GO 131-D will be considered.

CPUC staff released a Phase 2 proposal on May 17.

One objective is to provide definitions for terms included in the Phase 1 additions. In particular, “extension,” “expansion,” “upgrade,” “modification” and “existing electrical transmission facilities” aren’t defined.

This has been “causing applicants to be uncertain about whether a particular project will require a CPCN,” CPUC staff said.

CPUC staff have also proposed a streamlining measure for transmission projects included in one of CAISO’s annual transmission plans.

The CPUC process for issuing a CPCN includes a review under the California Environmental Quality Act (CEQA) and an evaluation of the need for the project and its cost.

CAISO also evaluates the costs and need for a project in its transmission planning process, the staff proposal noted.

The proposed change to GO 131-D would establish a “rebuttable presumption” that the project meets the CPUC requirement for need if it’s an approved project in a CAISO transmission plan.

That would be consistent with Assembly Bill 1373 of 2023.

A bill in the state legislature this year tried to take the rebuttable presumption a step further. AB 3238 by Assemblymember Eduardo Garcia (D) would have created a rebuttable presumption that the benefits of a transmission project outweighed its environmental impacts if the project was included in a CAISO transmission plan.

The bill is still alive, but the rebuttable presumption provision was removed. (See Bill to Streamline Transmission Development Advances in Calif. Senate.)

The CPUC staff proposal also looks for ways to speed up the application and CEQA review processes.

One idea is to allow applicants to submit a draft environmental document for their project. That would cut out a step in which the applicant provides a proponent’s environmental assessment, or PEA, which is followed by staff preparation of an environmental document.

The proposal would require applicants to consult with staff on the environmental document at least 12 months before submitting an application.

A comment period for the Phase 2 proposal ran through July 15. The CPUC expects to release a proposed order by Oct. 13.

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PJM MIC Briefs: July 10, 2024

PJM’s Market Implementation Committee endorsed by acclamation a PJM proposal to revise two financial inputs to the quadrennial review to reflect changing market conditions, particularly increased interest rates. The most recent review was approved by FERC in February 2022. (See FERC Approves PJM Quadrennial Review.) 

The proposal would increase the after-tax weighted average cost of capital (ATWACC) from 8.85% to 10% and use a 0% bonus depreciation rate for the 2027/28 delivery year and beyond. The original quadrennial review included a 20% bonus depreciation value for the 2026/27 year. The proposal also updated the Bureau of Labor and Statistics (BLS) indices used in capital cost escalation rates. 

The changes increase values for all five CONE areas by an average of $79/MW-day, with CONE Area 5 seeing the largest increase at $90/MW-day and Area 4 increasing by $65/MW-day. The proposal is slated to go before the Markets and Reliability Committee and Members Committee on Aug. 21, with a targeted filing date at FERC in August or September. 

PJM’s Skyler Marzewski said the automatic ATWACC adjustment was considered by staff and the Brattle Group — which was hired as a consultant for both the original quadrennial review and the re-evaluation of the financial parameters; however, it was determined that would provide minimal benefit, particularly if the review period is shortened to occur more often than every four years. 

Paul Sotkiewicz, president of E-cubed Policy Associates, said the changes improve the accuracy of the values for the 2027/28 delivery year but that the net CONE for the previous year remains “unrealistically low,” particularly since no merchant combined cycle generators have been financed in the past two years. The most recent quadrennial review included shifting the reference resource from a combustion turbine to a combined cycle unit. 

Marzewski said PJM opted against reopening those values, since doing so likely would require altering the Base Residual Auction (BRA) schedule. Sotkiewicz responded that proper price formation with the right cost of capital shouldn’t be sacrificed for timing and maintaining the auction timeline. 

PJM Presents Road Map of Market Design Changes

PJM outlined its expected timeline for several ongoing stakeholder processes and staff efforts to redesign several areas of the RTO’s markets to address reliability issues identified in its Ensuring a Reliable Energy Transition analyses. PJM’s February 2023 4R’s Report was part of that analysis and laid out many of the reliability concerns the road map focuses on. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.) 

PJM Senior Director of Market Design Rebecca Carroll said the road map was created to track the various working areas and ensure that none fall through the cracks. It is meant to be a “living document” that will be updated as new efforts begin or are completed, she said. 

Efforts already underway include the demand response performance window and accreditation, reserve performance and procurement during periods of operational uncertainty, load flexibility, regulation market signals and performance requirements, and FERC Order 841 requirements on electric storage market participation. The second phase of PJM’s capacity market redesign is expected to begin in the second half of 2024 and continue through 2027. 

The timelines on which work is expected to begin and be complete for each item are based on stakeholder issue charges, FERC filings and estimates from software programmers. 

The rules around generators with co-located load were considered as an independent item of the road map but are  included in the load flexibility category, Carroll said, adding that PJM is conducting a deeper investigation this year to look at what flexibility exists for data centers and large loads. 

Executive Vice President of Market Services and Strategy Stu Bresler said corresponding road maps are being created for operations and planning, with the latter being reworked to reflect FERC’s Order 1920.  

Vistra’s Erik Heinle said it’s important that PJM views the road map as a living document that reflects the shifting priorities of stakeholders. He expressed surprise that the design of the market seller offer cap (MSOC) and possible over-mitigation of offers wasn’t included in the document. 

“When you look at what is driving certain retirements, certainly mitigation is one,” Heinle said. 

Carroll said changes to market mitigation are included in a FERC refiling PJM is preparing with several components of its Critical Issue Fast Path proposal the commission rejected in February (ER24-98). (See “PJM to Refile Portions of Rejected CIFP Proposal,” PJM MIC Briefs: June 5, 2024.) 

Independent Market Monitor Joe Bowring replied there is no over-mitigation of market offers and defended the current design. 

Several stakeholders expressed support for ranking the items by importance with respect to PJM’s stated reliability concerns. Carroll said PJM thinks all the issues being discussed are high-priority and time-critical, but it is valid to consider the urgency of new issues that arise in the future. 

Voltus Discusses DR Market Issues

Demand response provider Voltus presented several issues related to the accreditation of DR participation in the capacity market, known as load management, focusing on capacity offers being limited by winter energy availability and how PJM’s effective load-carrying capability (ELCC) model determines availability. 

Voltus Vice President of Energy Markets Emily Orvis said the company supports expanding the hours DR is available during the winter to match the growing reliability risks PJM has identified in the evening winter hours, which she said would allow DR providers to shift their customer enrollment to capture loads that match that time, rather than looking solely at their winter peak hourly consumption. The Markets and Reliability Committee in May endorsed an issue charge to consider modifying the availability of DR resources, while rejecting a quick-fix proposal to expand the winter availability window by two hours into the evening. (See “DR Availability Issue Charge Approved, Quick Fix Proposal Rejected,” PJM MRC Briefs: May 22, 2024.) 

She said PJM’s practice of capping availability to the lesser of a facility’s winter peak load or peak load contribution (PLC) limits the participation of winter-leaning customers who could provide higher curtailment during that season. 

Additionally, some customers are able to reduce output to a greater degree than their winter peak load or PLC, but that additional capability is not included in the resource’s accreditation. She said Voltus’ energy availability in June 2024 was 25 to 30% higher than its accredited value. 

Resources also are capped by an ELCC modeling approach that assumes that DR availability is proportional to system load, reducing the incentive for customers with flat load profiles to participate. Rather than looking to simulated system loads relative to peak forecasts, she said PJM’s DR Hub holds more accurate information about the ability for a resource to reduce its output at a given hour. 

The caps to DR availability create multiple de-rates to resource accreditation that do not align with the incentives for customers to participate in the capacity market in a way that reflects PJM’s shifting view of when system risks are concentrated. 

Bowring noted that he disagreed with each of the key points made by Voltus and requested an opportunity to provide education at a future meeting.  

Manual Revisions Include ARR Trading Deadline

PJM’s Emmy Messina presented several revisions to Manual 6, including administrative changes and adding a deadline for auction revenue right (ARR) trades. The changes were drafted through the document’s periodic review. 

Requiring ARR trades to be submitted by noon ET on the business day before the auction opens allows time for PJM to complete its necessary analysis. Relinquish requests would have a deadline of noon on the business day before the opening of stage 2 of the annual ARR allocation process. 

The revisions also would disqualify transmission customers with firm services to charge energy storage or hybrid resources from receiving an allocation of ARRs. The language conforms with FERC orders in ER19-469 and ER22-1420. (See RTOs Move Closer to Full Order 841 Implementation.) 

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PJM PC/TEAC Briefs: July 9, 2024

Planning Committee

Elevate Reviews CIR Transfer Proposal

Elevate Renewables presented a first read on one of six proposals to revise how capacity interconnection rights (CIRs) can be transferred from a deactivating generator to a replacement resource interconnecting at the same site. (See “Stakeholders Endorse Revisions to CIR Transfer Issue Charge,” PJM PC/TEAC Briefs: June 4, 2024.)

The package would create a fast-track process for replacement resources to use to go through the interconnection process, provided they would have an equal or smaller output and CIR value as the deactivating retiring resource and no material adverse impacts to the grid are identified. Replacement resources would be required to interconnect at the same substation and voltage as the original resource, although use of a different breaker would be permitted.

Elevate envisions a nine-month time frame for most projects to get through the expedited process, with 60 days for initial application review, 180 days for a replacement impact study looking at any potential transmission violations, and 30 days for the interconnection service agreement (ISA) to be approved.

Projects would be allowed to continue through the generation replacement process if minor network upgrades are identified. A 90-day facilities study process may be required before the interconnection agreement can be offered.

Elevate’s Kun Zhu said resolving localized voltage issues would likely be seen as a minor impact, while violations requiring upgrading a line to a higher rating would require projects to shift to the full interconnection process.

The ability for projects to go forward with minor network upgrades stands in contrast to PJM‘s proposal, which would require the replacement resource to go through the standard interconnection process if any upgrades are identified or if available transmission headroom is changed by the addition of the resource.

Proposals have also been sponsored by Gabel Associates, PowerTransitions, MN8 Energy and the Independent Market Monitor.

The Elevate package would also permit standalone battery storage to be eligible for the generation replacement process, unlike PJM’s design. A companion study of the charging phase or separate load study would be conducted to identify any needs prompted by the charging phase. Zhu said the generation interconnection study process was designed solely for resources that would only inject energy into the grid, making the charging phase irrelevant to the CIR transfer eligibility discussion.

PJM’s Ed Franks said standalone storage is not permitted in the RTO’s proposal because that resource would not have been envisioned in the original network upgrade studies done on the retiring resource and the charging phase would conflict with PJM’s requirement that replacement resources have no grid impacts, such as changing line loading. Hybrid resources with a storage component would only be allowed if the battery could not charge off the grid.

Elevate’s Tonja Wicks said PJM has been messaging that new entry isn’t set to keep pace with deactivations and accelerating load growth, driving the need for process to quickly replace retiring generators with new resources. She also noted that only a small subset of projects that have cleared PJM’s interconnection queue in recent years have entered commercial operation, an issue she argued could be helped by focusing on proposals that can be quickly studied and are likely to be assigned minimal network upgrades.

“We need new approaches to address this new problem that we’re seeing as we deploy new technologies,” she said. “We didn’t have reserve deficits 10 years ago.”

Ken Foladare, of the Tangibl Group, said it’s likely to be well into 2025 before the proposal would be implemented if approved by stakeholders and FERC, putting it close to the targeted full rollout of PJM’s new cluster-based interconnection process. He questioned the benefit of the proposal if it is likely to go into effect around the same time that PJM is completing a process to speed interconnection for all resources.

Wicks said the Elevate package would establish a nine-month study process that would remain quicker than the two years she said it would likely take resources to typically clear PJM’s new approach. Not only would that allow some resources to receive ISAs faster, she said, but it would resolve a timing misalignment between when resources deactivate and when their CIRs can be passed on to a new resource.

PJM Proposes Load Analysis Subcommittee Charter Revisions

PJM presented revisions to the Load Analysis Subcommittee (LAS) charter that would shift its focus from collecting and presenting forecast data provided by transmission owners to reviewing the independent forecasts the RTO produces and its methodology.

Much of the status quo charter language focuses on collecting load data and developing forecasts, which PJM’s Molly Mooney said is a legacy of when TOs would submit their own forecasts to the LAS. The revisions instead focus on review of the end product forecasts and the data used to construct them.

“It’s definitely time to review and update our charter. The charter is also a legacy of when the Load Analysis Subcommittee members provided load forecasts to PJM and we gathered those materials and processed them … now PJM does an independent load forecast, so the role of the LAS has changed a little bit,” Mooney said.

Data Centers Challenge Light Load Forecast Case

PJM’s Stan Sliwa presented revisions to the light load case inputs used in the Region Transmission Planning Process (RTEP) load forecast, which aim to reflect the growth of load with flat profiles unaffected by weather and season. The typical example of such load, Sliwa said, is data centers that tend to consume a consistent amount of power throughout the year.

The light load case is designed to create an accurate representation of shoulder periods by scaling load down to 50% of the summer forecast peak using bus-level data provided by transmission owners. The proposal would limit that practice to not include any non-scalable load reported by TOs.

The Manual 14B changes also expand the NERC TPL standards examined during generator deliverability analysis to match current practice, updating the system operating limit (SOL) definition and adding new standards created by NERC.

Transmission Expansion Advisory Committee

3 TOs Negotiate Changes to Component Project in 2022 RTEP Window 3

NextEra Energy, FirstEnergy and Dominion Energy have redesigned the plans for a new 500-kV line between the 502 Junction substation and the new Aspen facility to reduce greenfield development and improve constructability. The project is a component of the $5 billion transmission upgrade package aimed at resolving reliability violations identified throughout Maryland and Virginia. (See FERC Approves Cost Allocation for $5 Billion in PJM Transmission Expansion.)

The proposed changes would replace a NextEra segment of the construction, which follows a greenfield route to the west of the existing 500-kV Doubs-Goose Creek line, with a design to continue the lines farther east towards the Doubs substation. Bypassing Doubs, the line would follow the existing corridor south through the Dickerson H substation and to the Goose Creek substation, where it would terminate, instead of at Aspen.

The reworked design would split the former NextEra component, which would cost $71.2 million, between FirstEnergy and Dominion, increasing the total cost by $167.5 million. NextEra would retain other components of the overall project amounting to $440.9 million, including building a new Woodside substation between the Black Oak and Doubs substations.

FirstEnergy would connect the line to the Doubs-Goose Creek corridor by rebuilding a 16-mile segment of the 138-kV Millville-Doubs line to be capable of supporting 500-kV overbuild. It would also be responsible for constructing an additional 15 miles south towards Goose Creek.

The Dominion portion of the work involves constructing the final 3 miles south into Goose Creek and installing a 500-kV capacitor bank originally destined for that facility to the Aspen substation.

Ratepayers along the revised corridors questioned the decision-making process for choosing which route would be selected and argued the change was shifting the impact from a wealthier area along the NextEra pathway to a different community.

PJM’s Jason Connell said the RTO is focused on arriving at the most optimal engineering solution.

Reliability Analysis Shows Growing Need for West-to-East Transfer Capability

Analysis of shifting load and generation patterns between 2028 and 2029 RTEP models find that rapidly growing load in PJM’s eastern regions could result in increased power flows from the west, where sizeable solar and wind development is expected to occur.

The MAAC region is forecast to see around 2,800 MW of load growth and 800 MW of new generation between the 2028 and 2029 summers, while the Dominion zone should see 2,500 MW in new load and 300 MW of added generation. While adequate generation growth is expected in the ComEd, AEP and Rest of PJM West zones to cover the load in the east, the analysis identified several voltage collapse violations in the summer across southern Pennsylvania, Maryland and Virginia.

PJM’s Jeff Goldberg said the analysis shows that the need for additional transmission linking the east and west is likely to present sooner than expected.

PJM Director of Transmission Planning Sami Abdulsalam said the analysis is meant to identify future needs and does not include any proposed solutions, adding that any transmission proposals are not bound to follow similar designs to past RTEP projects.

Supplemental Projects

Public Service Enterprise Group presented a $169 million project to construct a new 230/69/13-kV substation near Kenilworth, N.J., to address capacity overloads identified at its Springfield Road and Aldene substations. The new facility would be cut into the existing 230-kV Springfield Road-Aldene line and the 69-kV Springfield Road-Roselle line with a projected in-service date in December 2029.

Dominion presented a $42 million project to construct a new substation to serve a data center complex in Bristow, Va., which is projected to consume over 100 MW by 2029. The proposed Devlin facility would cut into the existing 230-kV Dawkins Branch-Vint Hill line and host nine 230-kV breakers configured as a breaker-and-a-half. The project is in the engineering phase and is targeted to come online in June 2026.

The utility presented a $30 million proposal to construct a substation to serve another data center in Mecklenburg County, Va., which is forecast to add 110 MW of load by 2028. The 230-kV Allen Creek switching station would cut into the 230-kV Finneywood-Cloud line. The design is in the conceptual phase with a projected in-service date of Dec. 30, 2025.

Dominion also said that around a dozen new substations will be needed across Virginia to serve data center growth, with most of the new load concentrated in Northern Virginia, including Prince William, Henrico and Charles City counties. The loads are expected to come online between December 2026 and the end of 2028.