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November 18, 2024

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BOEM IDs Oregon Wind Energy Areas

The U.S. Bureau of Ocean Energy Management on Tuesday selected two draft wind energy areas (WEAs) off the coast of southern and central Oregon, opening a 60-day review-and-comment period.

The WEAs comprise about 220,000 acres in the Coos Bay and Brookings call areas that BOEM outlined in February 2022. The bureau has yet to identify a WEA in the third call area off the coast of Bandon, Ore.

Together, the three large call areas could support up to 17 GW of generating capacity, but BOEM said last year it intends to consider 3 GW for near-term commercial development.

The draft WEAs further the Biden administration’s goal of deploying 15 GW of floating offshore wind in deep waters by 2035, BOEM said.

“As BOEM works to identify potential areas for offshore wind development, we continue to prioritize a robust and transparent process, including ongoing engagement with tribal governments, agency partners, the fishing community and other ocean users,” BOEM Director Elizabeth Klein said in a statement Tuesday.

“At the request of Oregon’s governor and other state officials, there will be a 60-day public comment period on the draft WEAs, and BOEM will hold an intergovernmental task force meeting in addition to public meetings during the comment period,” Klein said. “We look forward to working with the state to help us finalize offshore areas that have strong resource potential and the fewest environmental and user conflicts.”

The Oregon WEAs are the latest developments in the emerging market for West Coast offshore wind.

BOEM held the first West Coast wind auction on Dec. 7, 2022, when five lease areas off the California coast, with 4.5 GW of total capacity, brought more than $757 million in winning bids. (See First West Coast Offshore Wind Auction Fetches $757M.) Three of the lease areas are in Morro Bay off the coast of Central California, and two are in Humboldt Bay off Northern California.

The auctions were held after a multiyear process like that now playing out in Oregon. In California, BOEM identified large call areas, then selected WEAs within the call areas and eventually auctioned parcels to developers.

Oregon’s Brookings Call Area sits about 60 miles north of the Humboldt WEA, raising the possibility of collaboration between West Coast states on developing port infrastructure and a supply chain that takes advantage of economies of scale.

BOEM has yet to identify any call areas off the coast of Washington state.

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NJ Seeks Stakeholder Input on Pending Storage Program

New Jersey is asking for more stakeholder input to help shape its much-awaited plan to boost its storage capacity as it strives to reach 2,000 MW by 2030.

In a request for information issued Aug. 9, the New Jersey Board of Public Utilities seeks comments on four areas of its New Jersey Energy Storage Incentive Program (SIP) that will be key to the final proposal. Among them are:

    • what role electric utility companies should have;
    • how big and in what form incentives should be granted; and
    • how quickly and over what timeline storage approvals should be granted.

The BPU also wants input on the form of the incentives designed to help overburdened communities (OBCs) and a variety of smaller issues.

The request follows considerable earlier public input on the SIP proposal, with three BPU hearings in October and November that raised a number of contentious issues the board now wants stakeholders to help further clarify.

One of them is how to adjust, if necessary, the board’s initial proposal to prohibit utilities from owning storage projects, a measure designed to better stimulate private investment and ownership in the sector. After resistance to the proposal from utilities and their supporters, and backing from some interest groups, the BPU seeks comment on the advantages and disadvantages of “utility control verses non-utilities control” of energy storage systems. (See Utilities Oppose NJ BPU Plan Limiting EDC Storage Ownership.)

Critical Resource

New Jersey has for years prioritized storage development, believing it will help provide energy when intermittent sources such as wind and solar do not. Yet the state is only about a quarter of the way toward its 2,000-by-2030 goal. (See NJ Lagging in Energy Storage Progress.)

“Energy storage resources are critical to increasing the resilience of New Jersey’s electric grid, reducing carbon emissions and enabling New Jersey’s transition to 100% clean energy,” the BPU said in the order outlining the RFI. The program “will build a critical foundation for a long-term energy storage effort in the state.”

Hoping to jump-start the process, the board in October outlined the SIP, which aims to stimulate private investment in storage by awarding fixed annual incentives to both utility-scale and distributed projects and “pay for performance” incentives in certain situations. The program’s goal is to implement 1,000 MW of four-hour-plus storage by 2030. (See NJ Offers Plan to Boost Lagging Storage Capacity.)

The RFI poses a series of detailed questions about the two-tiered incentive plan. One question, for example, asks for stakeholder input on what would be the “fully installed cost” (in dollars per kilowatt-hour) for storage systems and how they would vary in New Jersey from other places. The RFI also asks how the BPU should structure its performance-based incentives, including a Peak Demand Reduction program, and whether it would work in New Jersey.

Another question asks whether modifications to the SIP are needed to maximize the ability of energy storage developers to access federal investment tax credits or other incentives. That issue could be important because the Inflation Reduction Act, signed a year ago, includes tax credits for battery storage systems.

The solicitation also asks, “How can BPU assure that the incentive structure chosen will in fact provide benefits to OBCs?”

Contentious Issues

The public hearings solicited numerous live comments and 61 written comments, the BPU said (QO22080540). While many people supported the plan, according to the solicitation document, “many commenters argued that the size of the overall program and individual capacity blocks” under which incentives would be awarded were too small, especially for distributed storage.

Two main points of contention emerged, the RFI said: “While many commenters agreed with staff’s proposal to not provide incentives for utility-owned energy storage, numerous others argued that utility-owned energy storage systems should qualify for incentives.”

In addition, “many commenters contended that energy storage developers and/or private owners should be able to retain control over their energy storage systems while earning performance incentives, while others argued such systems should be under utility control.”

In the second area of disagreement, some commenters felt the program should start slowly and scale up, while others said it should “start larger and scale back over time,” the solicitation said.

In a December letter to the board, the Center for Sustainable Energy (CSE) argued that the BPU’s incentive structure will “likely fail to efficiently unlock the benefits of energy storage.” Instead of paying the incentive over several years, the BPU should pay it as a lump sum “after the project has met all program requirements,“ the center argued.

“In CSE’s experience, requiring performance‐based incentives involves an elaborate and costly administrative structure where a simple one‐time payment easily can be made instead,” the CSE wrote.

AES Clean Energy, an Arlington, Va.-based clean energy project operator, said in a Dec. 12 comment that the company could not evaluate whether the BPU proposal to pay a fixed-incentive rate of $20/kWh is “adequate” without knowing the level of the second part of the subsidy, the “performance-based incentive.”

The letter suggested that the incentives be indexed to the price of lithium.

“Lithium costs are driving the cancelation of storage projects across the country that developers can no longer afford to build,’ the company said. “In order to keep within the bounds of the cost cap, the indexed incentive could include a ceiling.”

EV Dealers’ Storage Needs

In a Dec. 9 letter, the New Jersey Coalition of Automotive Retailers (NJCAR) urged the BPU to recognize the needs of car retailers and specifically include in the SIP language that “encourages investment in energy storage facilities that support dealership operations needed to sell and service the growing number of EVs being sold in New Jersey.”

The organization said the state’s auto dealers expect to spend $140 million on electric vehicle charging infrastructure in the coming years to service the EVs they sell and service. The submission, by NJCAR President Jim Appleton, said dealers likely will be forced to rely on “battery storage and battery-buffered solutions” to make up for the failure of grid-supplied electricity.

“New Jersey dealers have been advised in many instances that New Jersey’s utility companies are not positioned to meet the demands associated with that investment,” he said. “A bottleneck of EV charging infrastructure planning exists at the utility level that may prevent the dealers’ investment from being fully operational, since the utilities cannot supply sufficient power to the dealers’ sites.”

Utilities and their supporters argued in written comments against the BPU-proposed prohibition on utilities owning or operating storage, saying they have the experience and in-house knowledge to help the state meet its storage goals.

“Market hurdles (e.g., cost, supply chain, siting and permitting, immature revenue markets) and the exclusive reliance on third-party development may result in insufficient deployment of energy storage assets to meet the state’s goals,” the New Jersey Utilities Association argued. “If EDC [electric distribution company] ownership is not permitted/encouraged as part of the SIP, the board will miss an opportunity to leverage a critical business model to spur market development of energy storage.”

Public Service Electric and Gas, the state’s largest utility, made a similar argument but also suggested the BPU consider authorizing utilities to set up a pilot program to test the agency’s behind-the-meter program. The plan sets out a system in which a central operator reaches out to distributed storage resources in moments of high electricity demand so the resources can respond automatically and provide electricity.

“The cornerstone to a distributed storage program is an effective communication and call mechanism that is also cost-efficient, coordinated and standardized among the EDCs,” the utility said. It suggested the quickest route for the BPU to get there would be for utilities to test the system with their own distributed storage devices.

Such a pilot, the utility said, could “test the efficiency of its call mechanisms and the impacts that distributed storage deployment would have on the grid.”

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NRC Eases Emergency Preparedness Rules for SMRs

The U.S. Nuclear Regulatory Commission has moved to ease some of the crisis requirements for small modular reactors, potentially eliminating the emergency preparedness zones currently required near most nuclear reactors.

The long-running process (Docket NRC-2015-0225) was approved Monday by the four sitting commissioners.

The final rule — “Emergency Preparedness for Small Modular Reactors and Other New Technologies” — next goes to the Office of Management and Budget for review and subsequent publication in the Federal Register.

It will take effect 30 days after publication, which NRC staff estimates will be somewhere between mid-November and mid-January.

NRC will simultaneously issue “Performance-Based Emergency Preparedness for Small Modular Reactors, Non-Light-Water Reactors and Non-Power Production or Utilization Facilities.”

NRC said in a news release that the rule’s framework is based on technology and consequences.

Specifically, the technology in the new generation of SMRs is expected to be improved from the older reactors in use across the nation. And the consequences of an accident with a small reactor are potentially less severe than with a large reactor.

The rule gives applicants a scalable method to determine the size of the emergency planning zone surrounding their proposed facility — or to not even create such a zone — and develop a performance-based emergency preparedness program rather than the off-site radiological emergency planning requirements now in effect.

The new rule excludes fuel cycle facilities; currently operating research and test reactors; and large light-water reactors —those licensed to produce greater than 1 GW of thermal power.

Advanced SMRs are viewed as a potentially significant part of the clean energy transition, providing the emissions-free benefits of wind and solar generation with a much more stable power output, not reliant on variable wind or sunshine.

But to achieve widespread adoption, SMR technology will need to be perfected and be economical.

To achieve widespread acceptance, SMRs will need to win over people concerned that commercial nuclear fission carries health and safety risks.

Along these lines, the Union of Concerned Scientists criticized the NRC vote later Monday.

“Past natural and human-made disasters have taught us that having a robust and workable emergency plan in place is the key to minimizing human suffering and loss of life if the unthinkable happens. The NRC’s reckless decision today flies in the face of that experience,” said Edwin Lyman, director of nuclear power safety at the organization.

Stakeholders, the public and other government agencies submitted numerous comments in favor of and against the proposed rule as it was being finalized, and some NRC commissioners echoed some of the concerns in their own comments leading up to Monday’s vote. All four voted to approve, though Bradley Crowell registered disapproval of some aspects.

He commented: “We should recognize the collective lack of operating experience with these new technologies” and strike a better balance between easing their commercialization and adequately preparing for emergencies that involve them.

Commenters including the Federal Emergency Management Agency raised the same concern, Crowell said, adding: “I do not believe the draft final rule adequately reflects the concerns from these key stakeholders.”

He also said the frequency of emergency preparedness drills should be specified, given that the jurisdictions hosting SMRs may have no experiences with radiological emergencies.

Jeffrey Baran’s term on the commission recently ended, but not before he submitted comments.

Like Crowell, he raised concerns about emergency planning zones not extending beyond the gates of a reactor facility:

“Unlike a 5-mile or even 2-mile EPZ, a site boundary EPZ would not require dedicated offsite radiological emergency planning, and FEMA would have no role in evaluating the adequacy of a site’s emergency plans. With a site boundary EPZ, emergency responders would be left with all-hazards planning. While the NRC staff believes that all-hazards planning would be sufficient, FEMA and state emergency response agencies are not convinced.”

NRC Chair Christopher Hanson wrote that proposed rules do not preclude the emergency preparedness measures some commenters sought.

But it makes sense to have a flexible approach to SMR safety regulations, he said, because while SMRs are likely to be greatly variable in design and risk factor, they will have smaller reactor core, lower radionuclide inventories and smaller/slower fission product releases in the event of an accident — all of which would reduce risk to surrounding areas.

Hanson said NRC must be careful not to overstep its regulatory powers, but state and local entities can choose to implement safety plans of their own, and other federal agencies can support them.

Commissioner David Wright wrote: “Even if a determination is made that a formal offsite EP program is not required, the rule still requires that licensees maintain emergency plans that establish contacts, arrangements and procedures for coordination with offsite response organizations.”

Commissioner Annie Caputo said the rule is in line with congressional direction in the Nuclear Energy Innovation and Modernization Act, and will ensure decisions are objective, unbiased, scientific and protective of public health and safety.

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Report: Fuel Cells Key to NJ’s Clean Energy Future

Fuel cell technology could play a “critical role” in New Jersey’s drive to reach 100% clean energy, according to a state report released Aug. 8 that cited the energy source’s potential use in transportation, supplementing the state’s growing wind and solar sectors and acting as an emergency backup energy source.

The report by the New Jersey Fuel Cell Task Force, which Gov. Phil Murphy (D) created, outlines 21 recommendations on how the state should position itself to reap the benefits. It adds that the state is well positioned for such a move because of its high concentration of engineers and scientists, the network of research universities present and the “numerous industrial and chemical plants that could be used to generate hydrogen.”

Fuel cells have “the potential to reduce greenhouse gas emissions and harmful air pollutants and expand the state’s diverse clean energy portfolio,” the report says, echoing Murphy.

Fuel cells use hydrogen or other fuels to generate electricity, producing only water and heat as byproducts and emitting no greenhouse gases. In April, New Jersey and seven other states submitted a proposal seeking $1.25 billion from the U.S. Department of Energy to create a Northeast Regional Hydrogen Hub. (See Maine, RI Join Multistate Hydrogen Agreement.)

fuel cells

Schematic drawings of a how a fuel cell works (left) and a hydrogen fuel cell stack. | EIA/Fuel Cell Store

President Joe Biden authorized the hydrogen hub grants in the $1.2 trillion Infrastructure Investment and Jobs Act signed into law in November 2021. It provides $8 billion for four regional hydrogen hubs, $1 billion for research to bring down the cost of hydrogen electrolysis and $500 million to support equipment manufacturing.

Hub Proposal

Murphy created the task force to promote the use of cells in the state, and the body’s recommendations, according to the report, are designed to “create momentum in advancing fuel cells and hydrogen within the state and strengthen New Jersey’s hub proposal.”

Fuel cell electric vehicles (FCEVs) could be a key use of the technology, especially for medium- and heavy-duty vehicles, for which the battery weight, limited range and relatively long recharge time make battery power less viable, the report says. For similar reasons, technology could be extremely useful for buses, rail, marine vessels and material-handling equipment, the report says. (See Will Hydrogen Fuel Cell Vehicles Beat out Battery Electric?)

The faster fueling time of fuel cells, in particular, is a benefit, the report says. An FCEV can be filled up in about the same time as it takes to refuel a diesel engine, offering a timelier option than an electric battery, which can take hours to refuel depending on the strength of the charger, the report says.

“The state is also home to many large warehouses where fuel cell-powered material-handling equipment offers significant advantages over diesel or battery power in terms of emissions, productivity and lifecycle costs,” the report says.

The report’s other suggestions on how the state should strengthen its ability to take advantage of fuel cell technology include:

    • Explore ways to incentivize technology to improve local air quality;
    • Explore fuel cells as a non-combustion option for demand response programs, which provide alternate energy sources when high demand stretches the available electricity supply;
    • Consider options for state tax credits on investments or production of low-carbon hydrogen;
    • Encourage revisions in PJM’s tariff to include green hydrogen production;
    • Consider requiring electric distribution companies to propose state electricity resilience tariffs to help fund system strengthening measures;
    • Focus the Board of Public Utilities’ grid modernization program on valuing desired environmental attributes for distributed energy resources;
    • Spur FCEV adoption through incentives, bills, programs and tax credits;
    • Engage private sector industry partners to develop fuel cell and hydrogen-related pilot projects in New Jersey; and
    • Engage a broad hydrogen and fuel cell technology education, training and workforce development program.

Dispatchable Electric Supply

The report also sees the ability of fuel cells to turn on and off as a potentially useful source of dispatchable electric supply. That would help, for example, with “peak shaving,” offering a secondary energy supply to help handle peak demand periods and providing a supplement to intermittent sources, such as wind and solar, according to the report.

“The revenue that fuel cells receive for their value to the grid could be used as an incentive to promote their use as a replacement for diesel-powered emergency generators,” the report says. In addition, “less efficient peak load serving units create what is known as locational marginal emissions during peak load events; fuel cells directly offset these marginal emissions.”

Fuel cells also could be a source of backup power to the state, providing reliability and resilience, especially in situations in which natural disasters knock out power from the grid and can complement or provide a substitute to battery-based storage, the report says.

“Examples of fuel cells and hydrogen for backup power include small scale backup power (less than 100 kW), long-duration energy storage, microgrids and utilities,” the report says.

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DOE Launches Responsible Carbon Management Initiative

The Department of Energy on Friday made a series of announcements signaling that the Biden administration is doubling down on its commitment to develop and commercialize carbon management technologies as a critical element of its climate agenda.

The selection of two projects as the nation’s first regional direct air capture (DAC) hubs — one each in Louisiana and Texas — grabbed the headlines, but the two notices of intent (NOIs) released on the same day also show DOE digging in for the long haul, both on research and development and “responsible” implementation of its programs. (See DOE to Fund Direct Air Capture Hubs in Texas, Louisiana.)

Published in the Federal Register, the first NOI unveils DOE’s plans for a Responsible Carbon Management Initiative that will “encourage project developers and others in [the] industry to pursue the highest levels of safety, environmental stewardship, accountability, community engagement and societal benefits in carbon management projects.”

The NOI contains the agency’s Principles for Responsible Carbon Management, which cover community engagement and tribal consultation, environmental justice, transparency, long-term environmental stewardship, and regulatory and health and safety standards.

Since the passage of the Infrastructure Investment and Jobs Act, more than 100 carbon removal projects have been announced in the U.S., according to Brad Crabtree, assistant secretary of DOE’s Office of Fossil Energy and Carbon Management (FECM).

“That’s why this Responsible Carbon Management Initiative is so important,” he said in Friday’s announcement. “It will provide a framework for encouraging and recognizing best practices in the development of carbon management projects and for fostering transparency and learning through greater data and information sharing among industry, governments, communities and other stakeholders.”

The second NOI sets out DOE’s road map for new and ongoing research grants and prizes to advance its Carbon Negative Shot (CNS), one of the agency’s Energy Earthshot initiatives, which set high aspirational goals for improving the efficiency and cutting the costs of emerging technologies.

CNS is targeting “gigaton-scale deployment” for carbon dioxide removal technologies within the next decade, at a price of less than $100/metric ton of carbon dioxide captured, including the cost of monitoring, reporting, verification (MRV) and “durable storage.”

A gigaton of CO2 would equal 1 billion tons, or about one-fifth of total U.S. CO2 emissions in 2022, according to DOE.

Current prices for carbon removal technologies vary widely, from “low hundreds a ton and low thousands a ton,” said Noah Deich, FECM deputy assistant secretary, in an interview with NetZero Insider.

The agency defines carbon dioxide removal (CDR) as any form of carbon capture from ambient air or water, as opposed to capturing emissions from a power plant or industrial facility. The funding opportunities ahead will include pilots in small biomass carbon removal and storage, enhanced mineralization projects and marine projects, including direct capture from the ocean.

Biomass carbon renewal refers to technologies that use plants or algae to remove CO2 from the atmosphere, which in some cases may include combustion and carbon capture. Enhanced mineralization uses “alkaline materials such as calcium- or magnesium-rich crushed rocks spread over the ground,” according to a DOE fact sheet,

Other planned funding includes prizes for commercial-scale DAC pilots, smaller than the hubs, and funding for projects “developing and commercializing protocols, technologies and methods to improve MRV” of different carbon removal technologies.

Building the Market

Both the United Nations International Panel on Climate Change and the International Energy Agency (IEA) have framed carbon removal and storage technologies as essential to limiting climate change to 1.5 degrees or 2 degrees Celsius by 2050 or later.

In a 2022 analysis, the IEA said CDR should be part of a comprehensive strategy for reaching global net-zero emissions, but “not an alternative to cutting emissions or an excuse for delaying action.” The agency sees a more modest role for DAC, projecting that it would account for about 85 metric tons (MT) of CO2 removal worldwide in 2030 and 980 MT in 2050.

President Joe Biden and Energy Secretary Jennifer Granholm also have promoted carbon management technologies as central to the U.S. commitment to cut the nation’s greenhouse gas emissions 50-52% by 2030.

But to date, carbon capture and storage technologies have been used in the U.S. primarily for enhanced oil recovery (EOR) — that is, injecting CO2 into low-producing oil wells, first pushing out more oil from crevasses where the CO2 then can be permanently stored.

Both the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) provide major new funding to develop a range of carbon management technologies at commercial scale. The IIJA provides $3.5 billion for the development of four DAC hubs, which will include CO2 capture, processing and sequestration, at commercial scale.

As the first two hubs, Occidental Petroleum’s South Texas DAC hub and Battelle’s Project Cypress hub on the Louisiana Gulf Coast are slated to receive up to $1.2 billion of the IIJA funds. The projects also will be eligible to receive the IRA’s DAC tax credits of $180/ton for up to 10 years.

Occidental uses EOR extensively at its wells in Texas, according to the company website. However, during a Thursday press call, Kelly Cummins, deputy director of DOE’s Office of Clean Energy Demonstrations, said none of the carbon captured at the Texas or Louisiana hub will be used for EOR.

Rather, the CNS NOI positions the regional hubs as part of DOE’s efforts to build out a carbon management ecosystem. The NOI lists a dozen projects and prizes already announced and underway. Still, DOE notes, “The gap between the goals of CNS and the current commercial viability of some CDR technologies is substantial.”

The NOI “provides a strategy to coordinate funding opportunities that involve a variety of CDR pathways, technology readiness levels, and DOE offices and programs.”

To help build the market, DOE will use $35 million from the IIJA to underwrite carbon removal purchasing agreements, aimed in part at standardizing the credits produced by CDR. Microsoft and Climeworks recently signed a 10-year agreement for the DAC startup to capture and permanently sequester 10,000 tons of CO2 on behalf of the computer software giant.

Deich said the CDR purchase initiative is intended to “show how this tool can be scaled in the future and how it can drive innovation in the carbon removal space.”

The relatively small amount allocated to the program means it would have minimal impact on U.S. emissions, he said.

But standards are needed “in terms of what counts as carbon removal credits, how to actually go about measuring and verifying the carbon removal that … actually was delivered and stays delivered,” Deich said. “So, our aim in this program is to really help demonstrate what we think is best in class and hopefully crowd in a lot more private sector purchases in the near term.”

‘When Deployed Responsibly’

The Responsible Carbon Management Initiative is another effort to develop standards for DOE’s projects and the industry at large, and perhaps quell concerns and skepticism among some environmental groups, which continue to see carbon capture as a lifeline for the fossil fuel sector.

The Environmental Protection Agency’s proposed rule to use carbon capture and storage as a “best system for emission reduction” at fossil fuel power plants also received a mixed reception in comments from a range of industry stakeholders. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

Echoing IEA, the NOI on the initiative states, “When deployed responsibly, [carbon management technologies] are complementary [to], and not a replacement for parallel efforts to reduce emissions.”

DOE sees the initiative as a two-phase program, first developing the Responsible Carbon Management Principles and getting companies to commit to them. In the second phase, “FECM would provide resources to support project developers seeking to meet the principles or other aspects of this effort … [and] focus on evaluation of principle implementation, accountability and leadership.”

The principles outlined in the NOI focus broadly on different aspects of community engagement, equity and transparency. For example, developers are called on to consider the cumulative impacts a carbon management project might have on the community where it is located. Developers also should evaluate and mitigate environmental impacts and “publish environmental impact analyses and project monitoring data in a way that is timely and easy for the public to access.”

If the initiative is successful, FECM could develop “a robust recognition program” to raise the public profile of industry leaders and promote responsible carbon management, the NOI says.

The NOI also includes a request for information asking industry stakeholders for feedback on both the initiative and principles. Questions include whether the principles “would be likely to meaningfully advance carbon management,” whether stakeholders would either commit to or endorse them and what changes should be made to improve chances of industry acceptance. The deadline for comments is Sept. 11.

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SPP Markets+ Stakeholders Begin Tariff’s Development

PORTLAND, Ore. — Potential SPP Markets+ participants last week endorsed the first pieces of the day-ahead market’s tariff, acquiring a taste of the grid operator’s stakeholder process at the same time.

The core of that process is a focus on reaching consensus. It is ideally driven by stakeholders with SPP staff support, with a final agreement that satisfies a solid majority of members.

SPP Director Steve Wright, who chairs the three-person Interim Markets+ Independent Panel (IMIP) responsible for the market’s development, complimented the Markets+ Participant Executive Committee (MPEC) and its working groups and task forces for quickly adapting to the stakeholder process.

“I’m really impressed with the way that you’ve embraced democracy. Democracy can be messy, and it can be hard, but that’s what we’re doing here,” Wright said during the conclusion of the MPEC’s Aug. 8-9 meeting. “We love to see the participation; the way the voting structure is working; the way that motions create clarity around what it is that’s on the table, and then being able to move forward.”

John Cupparo, who along with fellow director Liz Moore fills out the IMIP, recalled the tariff discussion led by Bonneville Power Authority’s Russ Mantifel. Standing isolated in front of the MPEC for almost an hour and a half, Mantifel described how he was able to “flex the democratic muscle” — flexing his own muscles for emphasis — during workgroup discussions and gain confidence in the recommendations and motions that came forward.

Russ Mantifel, Bonneville Power Administration | © RTO Insider LLC

“I thought it was a very important point in terms of the confidence that it gave him and hopefully that group in terms of how the process works and what we’re building,” Cupparo said. “I’m hopeful that that confidence propagates and continues to propagate among the workgroups.”

Cupparo also noted the workgroup updates that filled the agenda included “natural” references to SPP staff and the SPP Market Monitoring Unit.

“It suggests that there’s a growing partnership, which is very important in this process, not only now but for the future,” he said.

With CAISO having about an eight-year head start in developing a Western RTO, and a group of utility commissioners from the West calling for an independent grid based on CAISO’s operating framework, that partnership could be key for SPP’s plans to offer “RTO-light” services that include day-ahead and real-time unit commitment and dispatch. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.)

SPP plans to complete this second phase of Markets+’s development by filing a completed tariff with FERC early next year. The IMIP and MPEC are expected to sign off on the tariff language in December, with the RTO’s Board of Directors taking up a vote in January.

Wright reminded Markets+ stakeholders that once the tariff is filed, potential participants will have to decide whether to proceed with costly systems development or wait for FERC’s approval. He urged further discussion on that next step during the MPEC’s upcoming virtual and in-person meetings.

“The SPP staff needs this guidance because this is an allocation-of-resources issue. Folks have got to know what their work plans are going to look like, and so we need some sense of what the market participants are thinking,” he said. “I know there’s a bit of a chicken-and-egg issue here. It’s, ‘Well, I need to know for sure the tariff is proceeding before I’m prepared to commit dollars.’ On the other hand, if we wait until everything is final, then it will have a significant impact on the overall scheduling and the go-live date for a Markets+ market.”

MPEC Chair Laura Trolese, with The Energy Authority, said that while the program is on track, there is “some potential risk” of the schedule slipping over approval of the “boilerplate” tariff language.

“The working groups have been a little hesitant to approve boilerplate language,” she said. “There’s been quite a bit of education and level-setting and bringing everyone up to speed.”

Trolese said stakeholders have reaffirmed moving forward with the boilerplate language, with an understanding that the final tariff will include changes to accommodate issues unique to the West.

Carrie Simpson, SPP’s director of Western services development and MPEC’s staff secretary, pointed out that the boilerplate tariff language the stakeholder groups have started with is limited to principles and concepts outlined in the Markets+ service offering that participants agreed to last year.

“It’s the SPP existing market design, and the SPP market design is largely based on MISO’s market design, which is largely based on PJM’s market design. These are best practices,” she said.

SPP’s Carrie Simpson (left) and MPEC Chair Laura Trolese confer before the meeting. | © RTO Insider LLC

IMIP Approves Virtuals’ Delay

The IMIP agreed with MPEC’s recommendation to delay the implementation of the price convergence financial product, or virtuals, by six months after the market goes live and with built-in circuit-breakers.

Virtuals are proposals to buy and/or sell energy at a settlement location for a specific time period in the day-ahead market. They were created to foster price convergence between the day-ahead and real-time markets and add liquidity. Settlements are based on the difference between the day-ahead and real-time price.

Stakeholders reasoned that virtuals, or the lack thereof, will not affect must-offer obligations. In addition, Markets+ boundary interface settlement locations are not eligible for virtuals. SPP will assess the settlement locations within a year of the virtuals becoming binding.

“My impression is that it was a rather robust conversation at the workgroup level, and it demonstrated that there’s differing points of views and there’s a way to get to a compromise or a consensus,” Cupparo told the MPEC. “That’s at the heart of what we do every day within the SPP way of life. That’s the model. That’s how it works.”

It was the only item the IMIP took up for consideration, saying it wanted to avoid interfering in the developmental work.

“There should be no sense of a signal that we have concerns about what’s going on. We’re trying to make sure that we’re not micromanaging you,” Cupparo told the MPEC.

The MPEC did endorse tariff language governing day-ahead and operating day activities, and LMPs and market clearing prices (MCPs). Committee members agreed a draft of language on scarcity pricing’s effect on LMPs and MCPs should be reviewed and brought back to the MPEC.

GHG Issue: ‘Emissions Leakage’

Clare Breidenich, who co-chairs the Markets+ Greenhouse Gas Task Force (MGHGTF), said the team is currently reviewing a draft and providing feedback on its tariff language, which is on track to be approved in October.

The task force’s primary objective is to develop a market solution, best practices, rules and protocols that support the Northwest’s only cap-and-trade program, that of Washington state, Breidenich told the MPEC.

“That program is already in place. Entities are incurring carbon obligations as of this year,” she said. “The live Markets+ would need to accommodate that program from the get-go.”

Labeled as cap-and-invest in Washington, the program began earlier this year with the Department of Ecology conducting the first two quarterly auctions. The department had to put up more than 1 million carbon allowances to help keep emitters’ costs in check after the May auction cleared at an unexpectedly high price ($56.10/allowance). (See Wash. Auctions Reserve Carbon Allowances to Relieve Price Pressure.)

Breidenich, who specializes in carbon policy, markets and regulations for the Western Power Trading Forum, said the task force is focusing on megawatt re-designation, or emissions leakage. This occurs when a change in market dispatch to accommodate the Washington program reduces emissions associated with generation serving load in the state but increases the market footprint’s emissions.

“The bulk of our work within the task force is trying to narrow down the definition of this problem to solve it,” she said.

The task force is evaluating the need for a multi-solve solution in the market-clearing engine and developing other options to minimize leakage, Breidenich said. The intention is to “identify what megawatts from what resources are eligible to be attributed to Washington state,” she said.

“Washington state is my bread and butter at this moment,” Breidenich said, noting that there is not perfect solution to the leakage problem.

“Anybody who has looked at this problem for any length of time realizes it pretty much is intractable. It is not caused by a deficiency in today’s market. It is not caused by a deficiency in the state program,” she said. “It is caused solely by the fact that you have a greenhouse gas pricing program in a limited geographic area with a much broader market footprint, full stop.”

“The only way you can fundamentally completely solve the leakage problem is if every jurisdiction within the market adopted a pricing program. We shouldn’t get too committed to the perfect solution because we won’t find it,” Breidenich added.

Clare Breidenich, Western Power Trading Forum | © RTO Insider LLC

Trolese pointed out that with carbon allowances clearing at more than $60, it amounts to a $30 adder to a participant’s energy prices.

“It’s a significant impact to market dispatch … that adds to the complexity,” she said. “There’s no perfect solution, but every imperfect solution has some pretty serious impacts to the market and different market participants.”

Several other western states have adopted greenhouse gas-reduction targets or have clean energy programs that don’t rely on pricing elements in their dispatch. Most of these efforts have a 2030 target before they become binding, allowing the task force additional time to determine how to incorporate them into the tariff.

“We’ve heard very clearly from regulators and market participants in those states that these are important, and we need to think about how the market solution can address these programs,” Breidenich said. “We are starting that work, but it’s going to be in a longer time frame than meeting the pricing program details.”

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SoCalGas, California PUC Settle Aliso Canyon Case

The California Public Utilities Commission issued a decision Thursday adopting a settlement over the massive leak at the Aliso Canyon Natural Gas Storage Facility in 2015 that includes a $71 million penalty against Southern California Gas, the facility’s owner.

As part of the settlement, SoCalGas agreed it would not try to recover $485.5 million in costs related to the incident and it would refund more than $18 million to ratepayers. It also admitted to a violation of Public Utilities Code section 451, which requires public utilities to operate their facilities safely.

The CPUC’s decision approved an agreement between SoCalGas and the CPUC’s Safety and Enforcement Division and Public Advocates Office.

“The settlement agreement … is consistent with the record in that it includes an admission of a safety violation of section 451 for the totality of the Aliso Canyon incident, as well as a significant fine consistent with the magnitude and impacts of the violation,” it says.

CPUC President Alice Reynolds and administrative law judges Jessica Hecht and Marcelo Poirier drafted the decision.

Ratepayer advocates opposed the settlement as premature and possibly inadequate.

The proceeding against SoCalGas was initially “phased,” with “Phase 1 devoted to the number and nature of violations and Phase 2 covering costs, fines and penalties,” The Utility Reform Network (TURN) and the Southern California Generation Coalition (SCGC) noted.

Phase 2 was never litigated, and the settlement bypasses it, TURN and SCGC said.

“Under the settlement, all of the Phase 1 and Phase 2 issues will be resolved, with SoCalGas bearing $610 million in purported monetary remedies in exchange for an admission of a single violation of [the] Public Utilities Code,” they said.

“Despite the extensive litigation that has already occurred, the key discussion of costs assigned to Phase 2 has not yet occurred [and] the record is insufficient to determine that the monetary remedies identified are appropriate,” they said.

The settlement overstates the dollar value of the settlement because “in order for the commission to assess whether the proposed monetary remedies are a sufficient penalty for the conduct at hand, the commission must first assess whether the included dollars would have been appropriate to collect from ratepayers under any circumstances,” TURN and SCGC argued.

The CPUC decision agreed “that a disallowance of cost recovery cannot be considered equivalent to a penalty unless the foregone amount was likely to be recoverable from ratepayers” but said that “in this instance, the settlement agreement clearly protects ratepayers from the risk of litigating hundreds of millions of dollars of potential costs, some of which likely would have been found to be reimbursable by ratepayers.

“In principle, we agree with the opposing parties that the settlement motion may overstate the value of the settlement for ratepayers; nevertheless, we find that SoCalGas’s agreement to forego cost recovery provides some (perhaps non-quantifiable but still real) ratepayer value,” the decision says.

The decision adopting the settlement, known as a presiding officer’s decision, takes effect after 30 days unless a party appeals it or a commissioner requests a public review.

“In case of an appeal or request for review, administrative law judges will assess and potentially modify the decision before presenting it to the commissioners for voting during a public session,” the CPUC said. “Commissioners may also offer an alternate decision for consideration.”

Proposal to Replace

In a separate proceeding, the CPUC has proposed replacing Aliso Canyon, the state’s largest natural gas storage facility, with a combination of non-gas-fired generation, building electrification, energy efficiency and storage. (See California PUC Proposes Aliso Canyon Endgame.)

The facility’s fate has been controversial since a ruptured pipe at the SS-25 well poured more than 100,000 tons of natural gas into the air, leading to a blowout and sickening nearby residents. The leak was contained after four months in February 2016.

After the gas leak, the facility reopened at reduced capacity in July 2017, but in November 2021, the CPUC increased its storage limits by 7 billion cubic feet (Bcf) to just over 41 billion Bcf amid concerns about winter gas supply. At the time, it rejected a plan to increase the allowable storage to 69 Bcf. (See CPUC Approves More Gas at Aliso Canyon.)

On July 28, the CPUC issued a proposed decision that would increase the maximum storage level allowed at Aliso Canyon from 41 billion cubic feet to 69 Bcf “on an interim basis to help secure energy reliability and protect against high natural gas and electric prices.”

The proposal is scheduled to be taken up at the CPUC’s Aug. 31 voting meeting.

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PJM MIC Briefs: Aug. 9, 2023

Stakeholders Endorse Proposal on Co-located Load

VALLEY FORGE, Pa. — The PJM Market Implementation Committee voted to endorse one of several packages to flesh out the rules around loads seeking to receive their power from behind the meter of a generator. (See “Vote on Rules for Generation with Co-located Load Deferred,” PJM MIC Briefs: July 12, 2023.)

A 51.2% majority of stakeholders supported Exelon’s proposal for co-located loads not considered to be receiving service from the wholesale grid, passing over three competing proposals. None of the four proposals for co-located loads receiving grid service received majority support.

The Exelon proposal would permit a generator to retain its capacity interconnection rights (CIRs) for the share of its output supplied to the co-located load, so long as that load curtails within 10 minutes of PJM calling on the generator to supply that capacity to the grid.

For co-located configurations to be considered to not be receiving grid service, they would need to be designed to ensure that they’re exclusively supplied by the corresponding generator and disconnected whenever they’re not being served by the generator.

The proposal would consider the generator to be a load-serving entity for the co-located load and levy all relevant load-serving entity (LSE) credits and charges.

The approach of allowing co-located load to not be considered receiving grid service — but assigning some of the charges a wholesale customer would be assessed to the generator — has raised stakeholder questions, with some arguing it could muddy the waters of state and federal jurisdiction.

PJM’s Tim Horger said the current rules for generators receiving grid service remain unclear without a package approved addressing those configurations, and he plans to examine the Exelon package for ways to discuss additional changes.

“I think we probably still want to do that, but we also want to take into account the Exelon package that was approved,” he said. “To be clear, we do have rules in place now and we are following them.”

Lynn Horning, of American Municipal Power (AMP), said any approach PJM plans to take on co-located load with grid service should be clear when stakeholders make their final endorsement vote on the Exelon package.

MIC Rejects Reactive Power Compensation Proposals

Stakeholders rejected four proposals to revise the compensation structure for generators providing reactive power service and voted to sunset the Reactive Power Compensation Task Force (RPCTF). Generator owners are required to submit a FERC filing for each facility providing the service to receive compensation, which creates administrative burden and lacks a standardized approach. (See “First Read on Reactive Power Compensation Proposals,” PJM MIC Briefs: July 12, 2023.)

The clean energy coalition (CEC) proposal, formed by a group of renewable developers, received the most support at 62.2% when compared to the other three packages. But it didn’t hold onto that support when compared to the status quo and failed to pass at 44.3% support.

The CEC package would create a cost-of-service structure with a flat rate based on the methodology FERC uses to evaluate reactive filings and would require testing to validate that generators receiving compensation are able to provide the service.

The PJM proposal would have determined each generator’s reactive capability, measured in MVAR, and compensated them monthly. Synchronous and storage resources would have been compensated based on their availability in the prior month.

The Independent Market Monitor made two proposals, the first of which would have eliminated compensation outside of existing markets on the basis that all generators are required to provide reactive service as part of their interconnection service agreement (ISA).

The Monitor’s second would have used a flat rate structure based on demonstrated capability, similar to PJM’s proposal, but would have phased out compensation.

The proposals would have affected only new generators or facilities entering new compensation agreements, with the task force’s scope precluding changing existing reactive rates. The MIC voted down a proposal to expand the task force’s scope to include existing service rates last month. (See “Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope,” PJM MIC Briefs: June 7, 2023.)

Danielle Croop, facilitator for PJM’s Reactor Power Compensation Task Force, said in the absence of a main motion to move to the Markets and Reliability Committee, stakeholders could decide to continue deliberations at the task force, move discussion to the MIC or sunset the task force and close the issue.

David “Scarp” Scarpignato, of Calpine, said it’s significant that none of the proposals gained support over the reigning rules and given that the task force began its work two years ago it’s unlikely more discussion would yield new proposals.

“It doesn’t look to me like it’s a good idea to go back to the task force. I don’t think it’s a matter of whittling down the existing proposals to better proposals, I think people like the status quo,” he said.

Scarp motioned to sunset the task force, which was approved by acclamation without objection.

First Reads on Proposals Addressing Multi-schedule Modeling in MCE

Package sponsors gave first reads of three proposals aimed at addressing the expected performance impact of implementing multi-schedule modeling in the rebuild of the market clearing engine (MCE). (See “Merged IMM-PJM Issue Charge on Multi-schedule Modeling Endorsed,” PJM MIC Briefs: March 8, 2023.)

The discussion stems from a finding that introducing the enhanced combined cycle (ECC) model and energy storage resource (ESR) and hybrid model into the Next Generation Markets (nGEM) overhaul of the engine would cause the amount of time it takes for PJM to determine what resources will clear in the day ahead market to become impractical.

For combined cycle generators, the number of different configurations they can operate in, with varying numbers of turbines paired with heat recovery steam generators (HRSGs) and multiple offers for each configuration, multi-schedule modeling could lead to an exponential increase in MCE computation times.

PJM’s Package A would address the issue by creating a formula that would select one offer resulting in the lowest total dispatch cost to be modeled in the MCE.

PJM’s Keyur Patel said the schedule selection built into the MCE is the most optimal approach, but he does not see any way of getting the benefits of including the new models into the engine without some compromises. A joint PJM and GT Power proposal would use the Package A approach, but consider only cost-based offers for resources that fail the three-pivotal-supplier (TPS) test. Price-based offers would be used for resources that pass the test, aside from price-based parameter-limited schedule (PLS) offers being used for capacity resources under emergency conditions.

The Monitor’s proposals could combine the lowest offer points and most flexible parameters from resources price and cost based offers under certain scenarios, impose offer capping and parameter limits to all resources that fail the TPS test and apply parameter limits to capacity resources during emergencies.

Deputy Monitor Catherine Tyler said there are market power concerns in the MCE which allow resources to inflate LMPs by using high markups and to extract uplift using inflexible parameters, both of which would be made worse by PJM’s proposal. She said that parameters other than minimum run time aren’t considered under PJM’s approach.

Endorsement of the proposals is scheduled for the Sept. 6 MIC meeting. Customized Energy Solutions’ Carl Johnson said deciding between the packages likely will remain difficult for stakeholders who aren’t as familiar with offer structures.

“For those of us who aren’t really in the weeds on this, this is a really difficult choice to make,” he said.

Voltus Brings Economic Demand Response Parameter Issue Charge

Voltus presented an issue charge and problem statement making the case that demand response resources lack the parameters other generators can include in their offers, limiting the consumers able to participate as an economic resource.

David Aitoro, of Voltus, said DR now can be dispatched for a single five-minute interval, then be curtailed only to be called on again in the third interval. For many DR participants, that may not match their curtailment capabilities and is not in line with parameters other generation resources can include in their offers, he said.

He also argued that many consumers who could curtail air conditioning systems could do so for one to three hours without a major impact to building temperatures, but there’s no capability to structure an offer to reflect that.

“It’s really DR that’s getting left out in the cold here,” Aitoro said.

Several stakeholders discussed the scope of the issue charge and how economic DR in the energy market relates to DR entering the capacity market. Aitoro said Voltus’ intent is to focus on the energy market, which could include resources that also offer into the capacity market.

PJM’s Peter Langbein said there’s around 8 GW of DR in the capacity market with corresponding energy market offers, most of which are in excess of $1,000/MWh. Economic DR also can offer separate energy-only offers, with about 2 GW doing so.

Scarpignato said generators are required to enter their most flexible parameters in their offers and those Voltus is seeking to include appear to reflect desires rather than true capability.

Exelon’s Alex Stern noted that discussion held at the Distributed Resources Subcommittee (DISRS) on the issue charge and problem statement was raised during the July MIC meeting, with stakeholders questioning if the topic fit into the group’s scope or if it should be discussed elsewhere. (See “Stakeholders Question Scope of Distributed Resources Subcommittee,” PJM MIC Briefs: July 12, 2023.)

MIC Facilitator Foluso Afelumo said the scope and proper group to host the discussion are the primary issues to be ironed out before a vote.

Stakeholders Discuss Proposals to Include Local Factors in Net CONE

Paul Sotkiewicz, president of E-Cubed Policy Associates, presented a second proposal to create rules for incorporating local considerations that could impact generators’ net cost of new entry (CONE), such as local or state regulations or legislation. (See “Discussion on Local Considerations for Net CONE,” PJM MIC Briefs: March 8, 2023.)

The package would create a fifth CONE area for the Commonwealth Edison region, which Sotkiewicz has argued will see significant impacts to generator lifespans under the Illinois Climate and Equitable Jobs Act (CEJA). PJM also automatically would create new CONE areas for any regions where new local factors cause a reduction in asset lifespan or set emissions limits that “imply a reference resource with different technology” than the current resource net CONE is based on.

Sotkiewicz said the proposal would capture the potential for hydrogen fuel blending or carbon sequestration requirements to increase operating and maintenance costs or introduce issues with the asset life.

If the reference resource were to remain a combined cycle generator at a point when those resources are being required to blend hydrogen, he said there would be a need to incorporate that in the energy and ancillary services (E&AS) offset and update its asset lifespan more regularly.

The PJM package would also create a fifth CONE area for the ComEd region but does not create any provisions for the future addition of new areas.

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FERC Approves NERC Transfer Study Funding Request

FERC on Thursday approved NERC’s plan for funding the interregional power transfer capability study ordered by Congress in June, which will require the ERO to redirect 2023 budget funds intended for other purposes and tap its Assessment Stabilization Reserve (ASR) (RR22-4).

NERC submitted the plan to the commission in June, shortly after its Finance and Audit Committee approved the plan in a special meeting. (See NERC FAC Approves Transfer Study Funding.) The proposal was developed after Congress ordered the study as part of the Fiscal Responsibility Act, passed in June.

The FRA requires NERC to deliver to FERC by December 2024 a study on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability and recommendations to meet and maintain total transfer capability. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

NERC calculated it would require $1.55 million in funds not accounted for in its budget because it did not know about the requirement to perform the study when it created its 2023 business plan. To accomplish this, the ERO decided to reprioritize its 2023 work plan to free up cash. The effort included deferring several projects planned for this year, along with the ERO’s intentions to fill three open positions in bulk power system awareness, engineering and security, and standards.

After these steps, NERC determined it still would need to draw $700,000 from the ASR to avoid a special assessment. In its filing to FERC, NERC described the use of the ASR — which is funded only by U.S. entities — as fitting because the U.S. federal government mandated the study without input from Canada’s government.

In its decision last week, the commission said it found NERC had “provided sufficient information to justify” its proposal to tap the ASR. No motions to intervene or protests were filed with FERC, and the commission indicated no disagreement with NERC’s reasoning.

FERC did, however, take issue with the ERO’s reason for filing the budget request. While NERC only asked permission to use the ASR, the commission observed that the ERO is required to seek the commission’s approval for any change in how it uses budget. This meant, in FERC’s eyes, that NERC’s proposal as submitted was incomplete.

Despite this mild rebuke, the commission acknowledged that NERC had justified the reallocation anyway, and “because we understand the importance of expediency in this matter,” FERC said it would approve both parts of the plan without requiring another filing from the ERO.

The commission’s approval means NERC officially can begin work on Phase 1 of the study. A NERC spokesperson told ERO Insider that staff expects to start this phase — which includes identifying areas of surplus and deficient generation; performing the transfer capability analysis; and identifying thermal, voltage and stability limits — on Aug. 15.

FERC’s decision accounts for only the 2023 expenditures; paying for the work to be done next year requires revising NERC’s 2024 business plan and budget, a draft of which the ERO already had completed before Congress passed the FRA. NERC’s Board of Trustees and board committees will meet this week in Ottawa to consider the revised budget.

According to the FAC’s agenda, the study is projected to cost $3 million next year. NERC plans to pay $400,000 of this with “repurposed contractor and consultant funds,” leaving a total budget increase of $2.6 million. This cost will be split evenly between the ASR and the Operating Contingency Reserve.

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PJM PC/TEAC Briefs: Aug. 8, 2023

Planning Committee

Stakeholders Endorse RRS Load Model

VALLEY FORGE, Pa. — The PJM Planning Committee last week endorsed the load model recommended by the RTO for calculating the load forecast for the 2023 reserve requirement study (RRS).

The selected distribution, derived from data from 2013 through 2019, has a more conservative estimation of future loads than the model used in the 2022 study, with loads being higher in most percentiles.

The study will set the installed reserve margin and forecast pool requirement for the 2027/28 delivery year and inform any modifications to the previous three years’ values.

Alongside the Probabilistic Reliability Index Study Model (PRISM) program, PJM will use software developed for the hourly loss-of-load modeling used for effective load-carrying capability (ELCC) studies in this year’s RRS. PJM says the ELCC software has the potential to produce better results and will generate two sets of data, which will be presented to stakeholders when the study is complete for endorsement of one set of outcomes. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)

The load model selection process is required only for the PRISM software, which requires normal distributions of data, whereas the PJM forecast data are empirical. The ELCC process models the monthly peak load uncertainty by deriving load scenarios and frequency weight for each delivery year between 2012 and 2021.

The top three performing load models all project PJM’s peak overlapping with the peak for the “World,” defined as MISO, NYISO, TVA and VACAR. The RTO recommends the World peak be moved to a different week in July to avoid the overlap, which historically it has found unlikely and would lead to a decreased capacity benefit of ties (CBOT) value.

PJM’s Patricio Rocha Garrido said in the past 24 years, the World and PJM have not peaked on the same day in just over half those years. The PRISM software used to conduct the load model analysis treats each day as a five-day week, which would compound the impact a coincident peak would have in the data.

PJM Presents Preliminary Capital Budget

PJM presented a $44 million capital budget to stakeholders, a $2 million increase over the amount it projects to spend in the 2023 fiscal year. The preliminary budget is dominated by the cost of current applications and systems reliability, facilities and technology infrastructure and application replacements.

Though the $44 million ask is an increase over recent years, PJM’s James Snow said the RTO remains within the $45 million range it expected to spend.

Spending on applications makes up nearly half the budget at $21 million, which includes upgrades to PJM’s Dispatcher Application and Reporting Tool (eDART) system, improvements to credit or risk applications and cybersecurity. Facilities and technology spending would sit at $11 million and include replacement of backup generators at the control center and server upgrades.

The $8 million in proposed application replacements includes spending on the Next Generation Markets Systems (nGEM) project being undertaken with several other RTOs to build a new market clearing engine and related software.

Spending on new products and services would be $3 million, while $1 million would be spent on interregional coordination.

Migration of eDART Accounts to New Platform Underway

PJM began the process of working with members to transition from managing their accounts through eDART to its Account Manager software. The migration of the 7,443 accounts in eDART started on July 25 and will continue through Dec. 13.

PJM’s Maria Baptiste recommended users begin transitioning as quickly as possible to give themselves time to work through any issues that may arise. The Account Manager dashboard can be used to create new user accounts, reset passwords, unlock accounts and grant or terminate eDART account access.

Transmission Expansion Advisory Committee

AEP Proposes $202 Million Rebuild of 345-kV Line

American Electric Power proposed rebuilding its 51.8-mile, 345-kV Desoto-Sorenson line, telling the Transmission Expansion Advisory Committee last week the majority of the lattice structures and conductor on the line are more than 70 years old. The utility proposed rebuilding the line in a double-circuit configuration at a $202.4 million cost, including new structure entrances at the Sorenson, Keystone and Desoto substations.

The line has experienced 22 momentary outages and 12 permanent outages since 2014. AEP has found that the paper-expanded conductor installed on it is difficult to splice during repairs because of limited replacement materials.

AEP also evaluated rebuilding the line as a single circuit, but it determined that because of the number of generators seeking to interconnect on both sides of the line, as well as its status as the only transmission connecting the Fort Wayne grid to the 345-kV Tanners Creek hub, a double circuit would be more appropriate. The cost of a single circuit rebuild was estimated at $187.4 million.

FirstEnergy Presents Data Center Interconnection Projects

FirstEnergy proposed $27 million in upgrades to meet a projected 336 MW in data center load growth near its proposed 230-kV Sage substation.

The proposal includes a $1.5 million expansion of the substation, including installing three additional 230-kV circuit breakers, two new transformers and two 34.5-kV buses. The 138-kV Bartonville-Meadow Brook line also would be upgraded with an additional wave trap and revised relay settings for $700,000.

The third phase of the project, estimated at $25 million, would add nine additional breakers to the substation, bringing the total to 15, and terminate the 230-kV Doubs-Eastalco line at Sage. The substation also would be looped into the 230-kV Doubs-Lime Kiln line.

PJM’s Sami Abdulsalam said the data center load was identified in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3, which is in the proposal selection phase, and the proposal addresses the interconnection requirements for the load.

Philip Sussler, of the Maryland Office of People’s Counsel, asked if there was any transmission headroom available from the deactivation of the Eastalco Aluminum plant, which used about 300 MW prior to its retirement in 2010.

FirstEnergy’s Larre Hozempa said some of that transmission capability has been consumed by load growth over the intervening decade and the new data center load is expected to be significantly larger than the plant’s. The load included in Window 3 was about 1,300 MW, with 900 MW already under contract.

Update on RTEP Windows

Abdulsalam also presented an update on the 2022 RTEP Window 3 and the first window of the 2023 RTEP, which opened on July 24 and is set to close Sept. 25. (See “2023 RTEP Window 1 to Open this Month; 2022 RTEP Window 3 Selections in September,” PJM PC/TEAC Briefs: July 11, 2023.)

Window 3 closed on May 31 after receiving 72 proposals from 10 entities, and PJM has completed the individual proposal screening and planning evaluation steps. It now is conducting proposal scenario evaluations. In developing and analyzing dozens of scenarios, PJM looks at the full proposals made and modifications to them, and combines elements to create mix-and-matched variants.

Abdulsalam said the window had an atypically low rate of cost-containment commitments, signaling that developers believe there is higher risk associated with the projects and it may be harder to ensure cost estimates remain accurate.

Ranking of the scenarios will include scalability to address future needs, use of existing rights of way, cost evaluation and avoiding redundant capital investment. Abdulsalam said part of the analysis will include looking at other proposed projects outside the window and evaluating if they can be modified or synergized with the RTEP to reduce costs. He said the $786 million in transmission upgrades associated with the deactivation of the 1,295-MW Brandon Shores coal generator near Baltimore is one such project.

Some of the proposals that were focused on addressing the 2027 model needs do not appear to be expandable to address needs expected in the following year, Abdulsalam said. Analysis of the 2028 model also shows more grid reinforcements needed in the eastern and southern Dominion regions.

PJM is aiming to hold a special TEAC meeting in October to present the window evaluation results, followed by asking the Board of Managers for approval in December.