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April 13, 2026

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PJM, States Discuss Challenges of Transmission Planning at MACRUC

PJM and other RTOs are seeing a “very dynamic” transmission system as older generation is retiring and a whole new class of generation comes online, Ken Seiler, PJM’s vice president of transmission planning, said at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) 26th annual Education Conference at the Nemacolin Woodlands Resort in Pennsylvania.

The impacts of generation retirements and additions on transmission were part of the discussion of the panel, “The Challenges of Interstate and Interregional Transmission: A Balancing Act.” The panel featured discussion on how PJM oversees interregional coordination among states with different decarbonization standards, the repercussions of canceling large transmission projects and how the RTO’s Regional Transmission Expansion Plan (RTEP) addresses state public policy objectives.

Seiler said the dynamic nature of the grid today is creating uncertainty for future planning, putting pressure on PJM and its engineers to envision how different transmission will look like even a year from now.

“We’re in the middle of a major transformation within our system, and the transformation’s going to be bumpy,” Seiler said. “It’s going to be uncomfortable for all of us, but it’s going to take a village in order to pull this all together to make this go smoothly.”

Decarbonization and the Grid

Delaware Public Service Commissioner Kim Drexler, who moderated the panel, asked Seiler what key steps PJM is taking to prepare planning for decarbonization and a decentralized grid.

Seiler said PJM is conducting renewable integration studies that are imagining what the grid may look like up to 15 years from today. Seiler said the studies look at what the grid needs to maintain reliability, what the system will resemble with increased renewable energy and the impacts of state renewable energy portfolio standards. (See PJM Annual Meeting Focuses on Balancing Decarbonization, Reliability.)

PJM is actively developing transmission plans to accommodate distributed energy resource and offshore wind goals, Seiler said, working through the DER and Inverter-Based Resources Subcommittee on the implementation of FERC Order 2222 and the state agreement approach with New Jersey for the interconnection of offshore wind. (See PJM Dusts off ‘State Agreement’ Tx Approach.)

Seiler said PJM will present its study findings by the end of the year.

Interconnection Queue

Drexler also asked Seiler about the challenges PJM is seeing in the growing interconnection queue for proposed generation projects.

PJM is seeing quadruple the volume of projects within the interconnection queue from just three years ago, Seiler said, and currently there are 200,000 MW of proposed generation in the queue for a grid system that currently handles 200,000 MW of generation. Seiler said the current system was only designed to handle 200,000 MW of generation.

“You’re not going to pepper in another 200,000 MW of generation on top of that and expect the transmission to be reliable,” Seiler said.

PJM is conducting interconnection reform at the stakeholder level to simplify the interconnection process, Seiler said, creating processes to allow for more flexibility for developers to change the size of units and the machinery used and to suspend projects for up to three years if issues arise. (See PJM Panel OKs Extension of Queue Deadline.)

Seiler said the current interconnection process has served PJM well for the last 20 years, but it was designed more for large combined cycle gas units that were being built in the early 2000s and not renewable energy resources.

PJM must simplify the interconnection process, Seiler said, to account for the renewable solar and wind units in the growing queue.

Maryland Public Service Commissioner Anthony O’Donnell said state commissions are getting unfairly blamed for being a “bottleneck” in the interconnection queue with renewable projects. O’Donnell said there are often good reasons a project takes longer to be studied by PJM, including significant changes that can create reliability issues.

State commissions will then take criticism from interested stakeholders that don’t realize a project has yet to come to them for approval.

“Oftentimes the fingers are pointed at the commissions, especially by the environmental community, the advocates and developers, and it’s really not in our wheelhouse yet,” O’Donnell said.

Canceled Transmission Projects

O’Donnell was asked about the impacts on states when large-scale transmission projects are canceled. Drexler highlighted the Mid-Atlantic Power Pathway that PJM’s Board of Managers canceled in 2012 and the recent decision by the Pennsylvania Public Utility Commission to reject the controversial Independence Energy Connection transmission project between the commonwealth and Maryland. (See Settlement on Abandoned East Coast Tx Line Wins FERC OK and Transource Challenges Pa. PUC Decision in Court.)

O’Donnell said the public doesn’t realize that when a project is approved at PJM through the RTEP process and then goes through an extensive hearing process at the state level, a great deal of money is spent on planning. He said those costs are ultimately passed on to consumers whether a project is approved or not or if work has started.

“These projects accrue costs, and these costs will be paid by our ratepayers,” O’Donnell said.

Seiler was asked how PJM “shifts gears” when a large transmission project is denied by a state or federal agency. Seiler said permit denials cause a great deal of work for PJM engineers who have to go back and re-examine all projects that were accounted for in the interconnection queue and do a “retool” of the removed projects.

“We have to restudy things to determine what is really necessary to come up with the most cost-effective and cost-efficient solution in order to maintain reliability of the grid,” Seiler said.

Cost Allocation Reforms

With large multistate transmission projects, O’Donnell said, cost allocation has become a controversial subject among state commissions. He said those controversies became evident in the region when the cost allocations of the Artificial Island project were being debated. (See Artificial Island Cost Dispute is Over — Almost.)

Seiler said PJM is taking an active role in revamping its policies on cost allocation as the need for more transmission grows clearer. He said if a customer causes a reliability issue, they’re charged to reinforce substations or lines.

“Cost allocation today is one of the leading obstacles to getting generation interconnected with our system,” Seiler said.

Advanced Energy Economy Managing Director Jeff Dennis, who previously served as director of policy development at FERC, said the states would “do well” to engage in conversations with the commission on cost allocation reforms. The current cost allocation policy was developed by FERC 20 years ago and dealt more with combined cycle generation, Dennis said, and the policy is going to need to change for future projects to multiply and be successful.

“It’s going to be so critical in terms of how your policies and the policies that are handed to you by your legislatures are achieved cost effectively,” Dennis said.

Rights-of-way Optimization

One of the most important concepts on the horizon of transmission planning is being in a situation with “limited rights of way,” Seiler said, by finding methods to optimize the existing transmission footprints and systems.

Seiler said more technologies are being developed to enhance existing transmission rights of way, pointing to smart valves and smart wires that can “choke off” a piece of line and increase electricity flows onto other lines.

PJM and the states need to look closer at advanced technologies to achieve decarbonization goals and grid modernization, Seiler said, but they also need help from FERC to develop incentives for new technologies.

“We have to start adopting some of these newer technologies that help us squeeze more megawatts through the existing transmission grid that we have today,” Seiler said.

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NRDC Urges EE Participation in NYISO ICAP Markets

The Natural Resources Defense Council on Wednesday urged NYISO to commit to expand its distributed energy resources participation model to facilitate energy efficiency participation in the capacity market as part of the ISO’s Order 2222 compliance filing later this month.

Order 2222’s definition of DER includes EE, which is “an essential resource” for achieving New York’s goals laid out in the Climate Leadership and Community Protection Act (CLCPA), NRDC Senior Attorney Christopher Casey told the Installed Capacity/Market Issues Working Group.

EE provides a variety of economic and social benefits by reliably and permanently reducing demand and thereby avoiding infrastructure costs, Casey said. It lowers customer bills, lessens inequitable energy burdens, enhances the effectiveness of other DERs and creates non-energy benefits such as lower emissions, improved comfort and satisfaction in buildings, and increased property values, he said.

The CLCPA’s short-term goals include 185 TBtu of customer-level energy reduction statewide by 2025, and the Public Service Commission identified EE as playing a key role in the state’s clean energy transition, a role amplified by the coming electrification of heating and transportation, Casey said.

NYISO estimates that the contribution from EE and codes and standards (EE/C&S) will grow about 10 times between 2022 and 2040. Casey referred to the 2021 Gold Book, wherein NYISO estimates peak load reduction of 8,229 MW and 47,768 GWh from EE/C&S by 2040. Compared with the 2022 forecast of 860 MW and 5,096 GWh, the 2040 estimate is almost 10 times more.

Operational Benefits

Several stakeholders disagreed that the order requires EE, which they said is not technically capable of providing capacity service.

Doug Hurley of Synapse Energy Economics presented the case for operational benefits and improved market outcomes from supply-side participation by EE, but first interjected to say that EE “is technically capable of providing capacity. I think it operates very similarly to a self-scheduled, daily cycle resource.”

Other such resources on the system are eligible for the capacity market if they choose to participate in it, and EE does the same thing, Hurley said.

“There are a couple of decades worth of measurement and verification work that go into showing how much energy efficiency is actually producing during certain hours of the day that we can rely on to demonstrate that,” Hurley said.

The Brattle Group recently published two new papers that highlight the importance of EE participation as a supply-side resource in capacity markets, and several adjacent RTOs have a track record of more than 15 years of successfully integrating EE that way.

NRDC recommended that NYISO promise FERC to include in a separate filing by a specific date a participation model for EE that the ISO will develop with stakeholders.

As to whether an industrial end user implementing EE might be eligible for capacity payments, Hurley said “that is a detail we have to work out. We have to make sure that whatever we decide fits in well with the entirety of the New York ISO markets and all the rest of the design aspects. I’ve heard it discussed in both ways in different regions.”

Proper accounting of EE is important for a market mechanism to work, and “the key here is that any one megawatt of energy efficiency is only counted on one side or the other [supply or demand], but not both,” Hurley said. “We would have to figure out what is the right version of this that makes sense of both the timing and the specifics of New York’s markets.”

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9 Western Governors Sign EV Infrastructure MOU

Governors from nine Western states last week signed a memorandum of understanding to create an “integrated and interoperable” network of zero-emission vehicle infrastructure to support travel and commerce throughout the region.

The agreement was the signature achievement of Oregon Gov. Kate Brown’s one-year term as chair of the Western Governors’ Association (WGA), which includes leaders from the 18 westernmost states in the continental U.S., Hawaii and the three U.S. territories in the Pacific.

In addition to Oregon, the states signing the MOU were Arizona, California, Colorado, Idaho, Nevada, New Mexico, Utah and Washington.

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Gov. Kate Brown | Western Governors’ Association

Brown, an advocate for electrifying Oregon’s transportation system and wider economy, last year adopted the Electric Vehicles Roadmap Initiative as her chair’s initiative. Her goal: to reach an agreement to establish a shared set of principles for EV infrastructure planning and create voluntary standards to ensure that chargers are widely accessible and usable by EV drivers. (See Ore. Governor Plots Western Roadmap for EVs.)

In her keynote speech for the WGA’s virtual annual meeting on Wednesday, Brown touted the collaboration behind the initiative, which entailed “work sessions, webinars, podcasts and countless phone calls and meetings.”

“In total, we revealed a common set of infrastructure, financial and logistical challenges that affect EV planning for the private sector, utilities and Western states,” Brown said. “Regardless of whether thousands, hundreds or a few dozen public EV charging stations are present in a particular state, EV design manufacturing, sales and infrastructure deployment all represent an incredible economic opportunity across the West.”

In keeping with the tone of her speech at last December’s WGA meeting, Brown made no mention of the environmental aspects of EV adoption. She instead focused on the potential economic benefits to Western states, likely a concession to the spirit of regional bipartisanship expected to prevail among WGA governors with widely divergent views about how to address climate change.

“The Electric Vehicles Roadmap Initiative recognizes that we all agree that the expansion of electric vehicle infrastructure is an economic imperative for our states. This mutual understanding promotes collaboration across the aisle and throughout the West to elevate and energize an issue that states are already working on both individually and collaboratively,” Brown said Wednesday.

Those collaborative efforts include the West Coast Electric Highway, an agreement among California, Oregon, Washington and British Columbia to build a network of fast-charging stations every 25 to 50 miles along Interstate 5 and U.S. Route 101 “to allow electric vehicles users to travel the length of the West Coast with the same certainty they would have if they were driving a gas vehicle.” Farther inland, Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming have joined up to create the Regional Electric Vehicle West Plan to facilitate EV travel in the Intermountain region.

The roadmap process worked to extend that collaboration, bringing together EV manufacturers, charging station developers and state and local agencies to develop findings on best practices for developing charging network infrastructure. Those findings, set out in a special report released Thursday, include:

      • Jurisdictional authorities should streamline zoning reviews by designating EV chargers as an “accessory land use.”
      • Authorities “should make permit application documents available to be downloaded and submitted digitally with the ability to provide electronic signatures.”
      • States should clarify that permitting reviews for EV charging stations are limited to health and safety requirements found under local, state and federal laws, and that local aesthetic requirements do not meet this threshold.
      • States and utilities should provide local authorities with educational materials on EV charging technologies and related planning considerations.
      • Siting partnerships between gas stations and charging station developers can eliminate the need for local traffic studies.

The report also lays out recommendations for the federal government, encouraging Congress and the Biden administration to:

      • use multistate partnerships to deploy federal EV infrastructure funds;
      • promote flexibility within the Federal Highway Administration’s Alternative Fuel Corridors Program;
      • enhance EV infrastructure at federal rest areas;
      • support the U.S. Department of Energy Clean Cities Coalition program; and
      • create efficient permitting and siting practices for EV infrastructure installations on federal lands.

“Congress and the administration should pay particular attention to the bipartisan, federally oriented recommendations we have developed and how they can be integrated into legislative measures and agency planning,” Brown said.

“Our state agencies will continue this partnership to ensure that end users have a consistent and reliable experience regardless of where they are traveling throughout the West,” Brown said. “And even though this MOU isn’t the right step right now for all WGA states, I continue to remain extremely excited that we all understand the economic importance of electric vehicles and are working to develop the infrastructure necessary to tap into the full potential of EVs.”

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Companies Must Disclose Financial Climate Risks, Attorneys General Say

Attorneys general from 12 states sent a letter to the Securities and Exchange Commission (SEC) in June asking it to require companies to provide detailed information about the financial risks their businesses face under a rapidly changing climate.

Those risks would include impacts from new regulations as states set goals to hit net-zero emissions within the next 30 years.

The coalition also demanded the SEC require companies to disclose their GHG emissions annually, as well as any plans to mitigate them.

“Requiring businesses to disclose their exposure to climate risk couldn’t be more important,” said Andrea Ranger, a shareholder advocate with Green Century Funds, a financial advisory firm that specializes in environmentally and socially responsible investing.

A regulation requiring financial climate risk disclosures from the SEC would give investors insight into the total risk of the business and fill a longstanding gap, Ranger told NetZero Insider.

“Then, investors and stakeholders can demand emissions reductions to protect their investments, and more importantly, sustain a livable planet,” she said.

The SEC started developing climate risk disclosures for companies in 2010, but they were never enforced. Now, the Biden’s administration is pressing the SEC to include climate as a risk factor.

But the commission must develop a universal standard to quantify and qualify risks, Ranger said.

Organizations such as the Task Force for Climate-Related Financial Disclosures (TCFD), the Sustainable Accounting Standards Board, the Global Reporting Initiative and CDP Worldwide are working to make those standards the mainstream for companies.

The TCFD recommends companies develop different climate risk scenarios depending on whether emission reduction goals keep global warming below 2 degrees Celsius.

Published evidence of emissions and climate risks provide transparency for investors and stakeholders on what companies are doing to reduce them, Ranger said.

Many oil, gas and steel companies already are quantifying risks internally. Last month, shareholders elected three new members to ExxonMobil’s board of directors to address the financial risks of the company’s climate change planning.

Transportation companies will be forced to quantify their emissions, along with companies that distribute products.

Enforced regulations from the SEC could speed up the adoption of electric vehicles, Ranger said, and push manufacturers to reduce their emissions, as well.

“End consumers don’t really know the names of manufacturing companies, so there may not be as much pressure on them in the public eye,” she said.

The pandemic showed that supply chains are particularly vulnerable to unexpected disruptions. At least $1.26 trillion is anticipated in revenue losses for suppliers within the next five years due to climate change, deforestation and water insecurity, according to a CDP Global Supply Chain Report released earlier this year.

And corporate buyers could inherit $120 billion in increased environmental costs by 2026.

“The climate crisis threatens serious financial harm for U.S. companies, financial markets and the investments our residents have made to fund their retirements or pay for their children’s college,” Massachusetts Attorney General Maura Healey said in a statement.

The attorneys general of California, Connecticut, Delaware, Illinois, Maryland, Michigan, Minnesota, New York, Oregon, Vermont and Wisconsin also signed the letter.

“Climate change is not a distant problem to be dealt with in the future; it is here, and it threatens the U.S. economy and its financial system,” they wrote in the letter. “Demand from institutional and retail investors for American companies to respond to the financial and other impacts of climate change has grown significantly.”

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MISO, TOs: More Time Needed for ROE Refunds

MISO and its transmission owners last Wednesday requested an additional nine months to refund transmission customers after FERC changed the TOs’ return on equity last year.

MISO and the TOs said they need until June 30, 2022, to crunch refund amounts. They said the existing Sept. 23 refund deadline was unattainable (EL14-12-004).

FERC last year enacted a 10.02% ROE for transmission rates effective Sept. 28, 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were intended at different times to replace the 12.38% ROE established in 2002, which FERC deemed excessive years ago.

The ROE saga roiled for years while FERC tried to align a prescribed “zone of reasonableness” that better reflected the financial data investors use when deciding to back transmission projects.

FERC ultimately said the 10.02% ROE should be considered effective Sept. 28, 2016. In all, MISO TOs must refund customers for the November 2013-February 2015 and Sept. 28, 2016-Dec. 23, 2020 periods. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)

MISO said it was requesting the extension with the “experience of many additional months of work on the resettlement process” under its belt.

“The majority of the refunds are expected to be complete before the end of 2021. MISO and its transmission owners have completed refunds for years 2013 through 2016 and currently are focused on refunds for the years 2017 and 2018, which are the years that involve the majority of the refund dollars,” the RTO explained to the commission.

The grid operator said it has completed all resettlements for TOs who use a historical test year methodology to calculate their transmission rates.

However, MISO said the remaining one-third of transmission owners use more complex forward-looking transmission rates with a true-up mechanism. It said the refund process is two-fold for TOs with forward-looking transmission rates because ROE revisions must be made through both the forward rate and the true-up.

The RTO also said it had already worked through some refunds under the 9.88% ROE before FERC declared the 10.02% figure effective last May. MISO said it then had to resettle and shave some refunds.

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ERCOT Stakeholders Sign Off on More Ancillary Services

ERCOT stakeholders on Wednesday approved a binding document revision that codifies the grid operator’s plans to deploy more operating reserves — and do so earlier — in anticipation of tight conditions this summer.

Jeff Billo, ERCOT director of forecasting and ancillary services, told the Technical Advisory Committee during a special webinar that the grid operator’s near-term strategy is to increase responsive reserve service procurement from 2.3 GW to 2.8 GW during peak load hours on all days and to increase non-spinning reserve service so that at least 6.5 GW of ancillary services are maintained for all hours of all days.

ERCOT will add 1 GW of non-spin for days when a higher potential of weather-forecast uncertainty could result in a higher net load (load minus wind and solar generation). The changes are effective July 12.

“Going forward, ERCOT is going to operate the grid with a greater margin between emergency conditions and normal conditions,” Billo said. “This will cover for the days when we are losing a significant amount of generation due to forced outages.”

The grid operator was forced to call for week-long conservation measures on June 14 when it lost more than 12 GW of capacity to mostly mechanical failures. It ended last week with nearly 10 GW of capacity still offline. (See Generation Outages Force ERCOT Conservation Alert.)

Billo said the forced outages have had a significant impact on ERCOT’s operating reserve margin.

“That change is a big reason we’re increasing the amount of ancillary services going forward,” he said. “You’re getting that physical responsive capacity on the system. We felt that was an important part of the strategy going forward.”

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Jeff Billo, ERCOT | © RTO Insider LLC

As Billo explained to TAC the week before, ERCOT staff is formalizing its forecasting processes, which rely on a staff meteorologist and various vendors. Operating days will be classified as having high, medium or low potential for forecast variabilities, findings that will feed into procuring additional AS.

“Meteorologists are not perfect. It’s a science and an art, and sometimes they miss,” Billo said.

Staff also considered relying on the reliability unit commitment process before deciding to increase AS deployment.

Stakeholders expressed some concern over potential price suppression but passed the other binding document revision request (OBDRR031) by a 25-2 margin, with two abstentions. Retailers Just Energy and Demand Control 2 opposed the motion.

“We rely on the volatility of prices in the current summer to reflect risk in forward summers,” said Luminant’s Ian Haley, who abstained from the vote, during TAC’s discussion. “If this change goes through and there is unbelievable price suppression for the entire summer, that has implications for forward prices.”

Eric Goff, representing the residential consumer segment, urged caution before voting for the measure.

“The consumer segment feels that while ERCOT has pretty clearly said it wants to be conservative in general, it’s reacting to recent events,” he said. “We can tell this has not been a clearly deliberative process. … We prefer this whole issue be revisited when the summer concludes in October.”

TAC directed its Wholesale Market and Reliability and Operations subcommittees to analyze the summer outcomes and provide recommendations during the committee’s October meeting. The WMS will also review the market effects of ERCOT’s more conservative procurement and deployment objectives, while ROS will review the volumetric impacts and the inclusion of constrained capacity in the grid operator’s calculation of physical responsive capability, TAC Chair Clif Lange said.

Billo promised the committee that the grid operator would update the market on its AS procurement by the 20th of each month. The 2022 cycle for updating ERCOT’s AS methodology begins in the fall.

ERCOT issued a market notice Thursday with the details.

In-person Meetings Return in September

ERCOT will resume in-person meetings on Sept. 1, beginning with the WMS meeting, staff told the committee.

The grid operator is considering a hybrid model to accommodate those not ready to return for face-to-face meetings and will share more details during the July TAC webinar.

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Energy Consultant Nominated for Open PJM Board Seat

The PJM Nominating Committee has selected a West Coast-based energy consultant to fill the open position on the RTO’s Board of Managers.

David Mills, the owner and principal consultant of Eaglecap Energy Consulting in Seattle, has been nominated to fill the seat held by Neil Smith, former CEO of generation developer InterGen. Smith announced his resignation from the board in April because he accepted an executive position with a company that “would have presented a conflict of interest” with PJM. (See Neil Smith Resigns from PJM Board.)

PJM CEO Manu Asthana announced Mills’ nomination in a letter to stakeholders last month.

Mills is a former senior vice president of policy and energy supply with Puget Sound Energy, where he worked for more than 18 years and also served as chief strategy officer.

In his letter, Asthana said Mills has a “demonstrated track record of strategic leadership” in the power and natural gas industries. Mills previously worked for the Bonneville Power Administration (BPA) and also served as a rescue swimmer and helicopter aircrewman aboard the USS Enterprise in the U.S. Navy.

“The Nominating Committee is confident that David will make significant contributions as a PJM board member,” Asthana said. “David has a great background that is very commercial and very steeped in strategy as well.”

Stakeholders will vote on Mills’ nomination during a special Members Committee meeting July 14.

The Nominating Committee, composed of five sector representatives and three board members, has been especially busy this year.

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Manu Asthana, PJM | © RTO Insider LLC

In April, the committee nominated Paula Conboy, former chair of the Australian Energy Regulator, and Jeanine Johnson, vice president of product security at Netgear, to replace board Chair Ake Almgren and board member John Foster. Stakeholders elected the new members at the Meeting of Members in May. (See PJM Stakeholders Elect New Board Members.)

After Smith announced his resignation in April, the committee resumed its search, assisted by the executive and board search firm Korn Ferry International, to identify a candidate to fill the vacancy.

Asthana acknowledged the committee’s work in the search process, saying it performed well after being called upon to nominate three different board members in less than a year.

“They have put in countless hours,” Asthana said. “They have been incredibly thoughtful and conscientious, and I have been really impressed watching them work.”

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Proposed NatGas Plants ‘Appear’ Contrary to NY Law, Regulator Says

New York’s environmental regulatory authority is seeking input on permits for two natural gas-fired power station proposals that it says “appear” inconsistent with the state’s climate law.

The New York Department of Environmental Conservation (DEC) released draft permits for the 536 MW Danskammer Energy Center and 437 MW Astoria replacement project and requested public comment by Aug. 29.

“The climate crisis is one of New York’s top priorities,” Commissioner Basil Seggos said on Twitter Wednesday, adding that while there is no final determination on the permits, “DEC found that the current applications haven’t justified the projects or shown compliance with New York’s climate law.”

Opponents of both projects say the facilities are unnecessary and do not align with New York’s emissions requirements.

In March, Rep. Alexandria Ocasio-Cortez joined eight other Democratic U.S. representatives for New York asking Gov. Andrew Cuomo and DEC to consider green infrastructure as an alternative to the Astoria project.

“Moving forward with the implementation of new natural gas-fired power creates nuisances and real health hazards, which the community has vocally opposed,” the legislators said in a letter. “Frontline and diverse communities, like the ones we represent, stand to be disproportionately exposed.”

The Astoria facility is located adjacent to an area of the Bronx that is colloquially known as “Asthma Alley.”

In notices for both projects’ draft permits, DEC said that there are potential substantial GHG emissions associated with the proposed facilities.

“Based on the information currently available, it appears that the proposed [projects] would be inconsistent with or would interfere with the attainment of the statewide GHG emission limits established in the [Climate Leadership and Community Protection Act],” DEC said.

If a proposed project is inconsistent with the law, DEC must justify the project and identify alternatives or GHG mitigation measures.

DEC said it cannot satisfy either requirement without further input.

“We understand [DEC] has not made a final determination related to the [Astoria] project’s consistency with the [CLCPA]; however, as outlined in the project’s draft environmental impact statement, the project is estimated to reduce statewide greenhouse gas emissions by more than five million tons through the year 2035,” David Schrader, senior manager for communications east at NRG Energy, said in an email to NetZero Insider. “In addition, as a long duration backup/standby unit, the project facilitates the reliable interconnection of large amounts of intermittent renewable energy as required by the CLCPA.”

Danskammer Energy believes its upgrade project is “fully consistent with the CLCPA,” according to Michelle Hook, vice president of public affairs.

“Our repowering would replace a 70-year-old power plant with a highly efficient unit that will result in a reduction in statewide greenhouse gas emissions,” she in an email to NetZero Insider. “The new unit would displace not only our own existing power plant, but also other regional electric generation units that emit significantly more greenhouse gases.”

Proposals

As proposed, the Danskammer Energy Center project would replace gas-fired/oil-fired generators at the existing Danskammer station in Newburgh, N.Y., with a gas-fired/ultra-low sulfur diesel (ULSD)-fired combined cycle generator.

“The events of the last few days, during which New York City residents received emergency alerts to reduce power usage, illustrate the continued need for new, reliable power to support and back up our growing renewable grid,” Hook said. “Danskammer believes the issuance of our draft permit recognizes the need for New York to work together with power generators towards achieving its climate goals.”

Hook said the company looks forward to working with NYSDEC on appropriate mitigation measures to move the project forward.

NRG’s proposed Astoria station upgrade in Queens would replace natural-gas and oil-fired combustion turbines with one natural gas-fired/ULSD-fired simple-cycle generator.

In 2010, NRG proposed replacing the existing units with a 1,040-MW facility but modified the proposal last year to 437 MW.

The company is “pleased” with DEC’s decision to issue the draft permits and deem the project application complete, Schrader said.

“This is an important step in securing an affordable and reliable future electric system for New York City,” he said. “As the last few days demonstrated, the need for reliable power is as great as ever and will continue for years to come.” Modernizing the generating station, he added, “ensures that schools, hospitals and homes are powered more efficiently and with dramatically lower emissions.”

NRG expects to begin construction as soon as the permits are finalized, Schrader said, adding that the project will bring more than 500 new jobs to Queens.

“We remain grateful for the ongoing support of our neighbors, labor and trade unions, business leaders and community groups,” he said.

NRG, he added, is looking forward to receiving public input on the project and “working with DEC to ensure the project is consistent with New York State’s aggressive climate goals.”

DEC plans to hold a public hearing for the draft permits in the “near future.”

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CAISO Issues Urgent Call for More Summer Capacity

Citing record-breaking heat waves and worsening drought, CAISO on Thursday said it would exercise its rarely used power to call for additional capacity this summer to avert shortfalls and rolling blackouts.

“Summer has barely begun, and we have already had repeated extreme heat events creating dangerous conditions and shattering records across the country,” the ISO, California Public Utilities Commission (CPUC) and California Energy Commission (CEC) said in a joint statement.

CAISO had issued a resource deficiency warning in June after two generators tripped offline in a brutal heat wave, and the Pacific Northwest experienced extraordinary heat earlier this week. Portland, Ore., hit an all-time high of 116 degrees Fahrenheit, while Seattle reached 108 F.

“As a result of these unprecedented climate change-driven heat events, which are occurring throughout the West in combination with drought conditions that reduce hydroelectric capacity, California is using all available tools to increase electricity reliability this summer,” it said. “As part of this effort, the ISO has decided to exercise its authority to procure additional capacity again this year.”

“The ISO’s action is supported by a request by the CPUC and CEC and is taken out of an abundance of caution to ensure electric reliability and preserve the public health and safety of all Californians.”

The last time CAISO used its capacity procurement mechanism was during last summer’s severe Western heat waves, which caused the ISO to order load shedding with rotating outages in August and to declare energy emergencies in September.

Since then, the ISO and CPUC have taken steps to prepare for this summer. The CPUC ordered the state’s three large investor-owned utilities to procure thousands of megawatts of additional capacity, while the ISO instituted market rule changes meant to reduce transmission constraints and other problems that contributed to the August blackouts. (See CPUC, CAISO Take Major Steps for Summer Reliability.)

A huge increase in battery storage was expected to help cope with evening peak demand during heat waves, but some of the expected resources have failed to materialize, CPUC President Marybel Batjer and CEC Chair David Hochschild said in a letter to CAISO CEO Elliot Mainzer that requested additional procurement.

The state’s summer resource adequacy program “had relied on incremental resources coming online for the summer months,” it said. “The CPUC recently received notice that several will be delayed by one to several months, and in some cases will push online dates past the summer window.”

Last summer’s shortfalls occurred during the evening net peak, after solar power ramps down but air-conditioning demand remains high. CAISO and the CPUC hoped hundreds of megawatts of new lithium-ion batteries to store solar and wind power would cover that evening peak, but it may not be enough, Thursday’s action acknowledged.

During a recent CPUC meeting, Batjer said that batteries being shipped from overseas were delayed in transit.

In an email Thursday, CPUC spokesperson Terrie Prosper said that 3,160 MW of new resources, mostly batteries or solar paired with batteries, were anticipated to be online by August 1st. Currently, at least 2,705 MW will be online, and that number will likely increase, she said.

“According to project developers, some of these delays have been COVID-related (e.g., workforce slowdowns), while some have been due to supply-chain issues, including shipping incidents overseas,” Prosper wrote.

Hydropower, one of the state’s main summer resources, is quickly dissipating after an extremely dry winter with early snowmelt. Lake Oroville and Lake Shasta, major hydroelectric generating reservoirs in Northern California, are at 32% and 38% of capacity, respectively, the California Department of Water Resources reported Wednesday. Such low levels could lead to a halt in generation.

The drought has reduced hydropower capacity by 1,000 MW, the CPUC and CEC said.

In addition, demand response programs ordered by the CPUC have not been as effective as anticipated, the letter said.

“The aforementioned events have resulted in a material difference from what the CPUC assumed for the resource adequacy program in establishing requirements for summer 2021 and caused a material change in system conditions,” Batjer and Hochschild wrote. “While the CPUC, CEC and CAISO are collectively working on a number of strategies to address reliability concerns under extreme conditions, these changed circumstances require every tool that is available to the state to be deployed to ensure reliability this summer.

“Accordingly, the CPUC and CEC jointly request the CAISO to use its tariff-based authority to procure additional resources. We specifically ask that the CAISO procure capacity pursuant to its tariff authority for July and August 2021. We also request the CAISO to consider procurement for the September 2021 resource adequacy compliance month if conditions do not improve.”

CAISO’s tariff defines an event triggering use of its capacity procurement mechanism (CPM) as a “substantial event, or a combination of events, that is determined by the ISO to either result in a material difference from what was assumed in the resource adequacy program for purposes of determining the resource adequacy capacity requirements, or produce a material change in system conditions or in CAISO Controlled Grid operations, that causes, or threatens to cause, a failure to meet reliability criteria,” the ISO said in a message Thursday.

CPM Details

CAISO issued a market notice Thursday asking scheduling coordinators with non-resource adequacy capacity willing and able to receive a CPM designation to submit a Customer Inquiry, Dispute and Information (CIDI) ticket as soon as possible — and preferably by July 7.

The ISO is targeting capacity that is at least available during the net-peak hours of 4 p.m. to 9 p.m. Imports must be deliverable to the ISO at a delivery intertie and supported by firm transmission rights — or a reasonable equivalent — to the intertie.

“In addition to submitting a CIDI ticket, parties with capacity available to meet this significant event should also submit offers to the intra-monthly [competitive solicitation procurement] for August, September, and October,” the notice said.

Interested suppliers are asked to submit their tickets with the subject line “Summer 2021 CPM Significant Event” and include the following details:

  • resource IDs;
  • volume of megawatts available for the CPM;
  • dates the capacity is available to serve as CPM capacity;
  • whether the supplier is likely to accept a 60-day designation extension if it were offered;
  • whether the supplier intends to seek compensation above the soft offer cap through a cost showing approved by FERC.

CAISO has scheduled a stakeholder call for Friday at 10 a.m. to discuss the CPM action.

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Hydrogen May Hold Key Role in Deep Decarbonization, EPRI Panel Says

The net-zero energy system of the future may rely on many integrated, hybridized resources to reach even the hardest-to-decarbonize sectors, and hydrogen is a rising star in that scenario.

It could help grow long-duration energy storage needed for a renewables-heavy grid, or it can be a lifeline for nuclear power or natural gas.

“If we want to reduce emissions at an affordable cost, while also maintaining grid reliability and resilience, we need to use all the resources that we have, which means coordinating the use of nuclear, renewables and fossils with carbon capture to meet growing energy demands,” Shannon Bragg-Sitton, Integrated Energy Systems lead at the Idaho National Laboratory, said on Wednesday.

At the National Lab, nuclear power is seen as a decarbonization enabler, even though it is struggling in today’s market.

“Nuclear energy currently provides more than half of our non-emitting electricity, but unfortunately, it’s being pushed out of the market in many regions due to a glut of renewable energy … and historically low-cost natural gas,” Bragg-Sitton said at the Electric Power Research Institute’s Electrification 2021 forum.

But an energy market that has a demand for hydrogen could give the existing U.S. nuclear fleet more to do.

“The primary output from a nuclear plant is heat, and we believe that we should be leveraging that heat more effectively,” Bragg-Sitton said. “Rather than reducing reactor power when we have low net electricity demand, we can redirect that heat and electricity to energy storage for later use.”

To that end, she said, the U.S. Department of Energy is supporting demonstration projects that will produce hydrogen on site at nuclear facilities starting this year.

Mitsubishi Power Americas is betting on hydrogen being a go-to long-duration energy storage option for accommodating high amounts of planned renewable generation.

“You can envision a world where we’re probably going to have curtailment of renewable generation on some days, and we might run short to meet peak demand on others,” Todd Brezler, vice president of marketing at Mitsubishi Power Americas, said. “We think long-duration storage — typically in the form of green hydrogen — is a good solution in terms of having technologies available that we really know how to use.”

The company also is looking at blue hydrogen produced with natural gas and is investing heavily in geologic storage for green hydrogen through its proposed Advanced Clean Energy Storage project in Utah and other potential hydrogen hubs around the U.S.

Hydrogen also could have a role to play in putting existing infrastructure to work in a post-natural gas world, according to Mike Rutowski, senior vice president of research and technology development at Gas Technology Institute (GTI).

The institute has a vision for a “carbon-managed future” that integrates the electric and natural gas systems and leverages hydrogen, carbon-neutral fuels or biofuels to repurpose the existing gas infrastructure.

In that vision, the existing gas system is a long-duration energy storage asset that can be decarbonized, Rutowski said. Hydrogen is produced with clean electricity and stored in the existing gas system to be accessed when needed to make energy.

“To do that, we need continued R&D planning and investment decisions and to think about the whole energy system and the broad menu of technology pathways that we can use to meet all of the energy uses economy wide in a decarbonized way,” he said.

Incentivizing Hydrogen

Building out a hydrogen market to reach net-zero by 2050 is going to take incentives and market signals akin to what made renewables competitive today.

Production tax credits and renewable portfolio standards, for example, would go a long way to make hydrogen stand up against low-cost natural gas, according to Rutowski.

Green hydrogen currently costs about $6/kilogram, which is about $45/MMBtu, he said. If the cost drops to an anticipated $1/kilogram with technological advancements, it is still going to be $7/MMBTU. That will not compete against abundant gas at $2/MMBtu.

“That is still a significant cost gap that’s going to require the combination of incentives, market demand and investor pressure as well as companies taking the first move to build the infrastructure and be the first movers,” he said.

It is also important to put a social value on green hydrogen and support first movers in the market, Bragg-Sitton said. Public-private investments are an important way to help scale up technologies and hit a $1/kilogram price within the decade.

Government also can provide an incentive for end use in manufacturing to build demand.

“[We can] incentivize production to grow the market for that clean hydrogen so that we can introduce clean technologies all the way down the line, from the generation of energy to utilization and moving that energy downstream to the product level,” Bragg-Sitton said.

Energy market signals are another measure that will encourage development of long-duration energy storage with green hydrogen, according to Brezler. Mitsubishi, he said, is encouraged that some markets, such as California, are beginning to look at how to compare the per-kilogram cost of hydrogen to other energy storage fuels. (See Panel Examines Future for Green Hydrogen in West.)

The U.S. Department of Energy’s Loan Programs Office offers an important mechanism for the hydrogen market to grow, Brezler added. The LPO invited Mitsubishi in May to apply for up to $595 million to develop the proposed Advanced Clean Energy Storage project.

“Those types of loans help you get over that chicken-and-egg problem, where you’re able to start investing in the infrastructure and get going on green hydrogen,” he said.