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November 11, 2024

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NIPSCO Proposes New Gas Plant; Ind. Consumer Advocate Displeased

Tensions are building over Northern Indiana Public Service Co.’s proposal last week to build a new natural gas peaking plant at its R.M. Schahfer Generating Station.

NIPSCO filed for permission with the Indiana Utility Regulatory Commission (IURC) to install a 400-MW, $643.7 million natural gas plant (45947). According to NIPSCO, the plant would be in service at the end of 2026 and replace two soon-to-be retired coal units at the Schahfer station. The utility intends to transfer the retiring units’ interconnection rights on the MISO transmission system to the new plant.

The utility is also proposing to use construction while in progress (CWIP) ratemaking, which would allow it to start billing customers for the plant prior to construction and commercial operations.

The Citizen Action Coalition of Indiana, an environmental and consumer advocate, says the new plant will be costly, unnecessary and detrimental to the clean energy transition.

Ben Inskeep, program director at CAC Indiana, said NIPSCO’s proposal means it has “backtracked” on its 2018 integrated resource plan, which saw no need for new fossil fuel plants.

“One of the troubling aspects of NIPSCO’s certificate of public necessity and need filing for up to 442 MW of new gas turbines is that it is inconsistent with its current IRP,” Inskeep said in a statement to RTO Insider. “NIPSCO’s 2018 IRP found that no new fossil gas resources were needed. NIPSCO’s 2021 IRP included a preferred plan that has ‘up to 300 MW’ of new gas. However, NIPSCO unilaterally and without stakeholder input conducted additional analyses after it completed its 2021 IRP that it now claims supports its decision to increase its new natural gas capacity by 47% relative to its most recent IRP.”

NIPSCO insists the gas-fired plant is necessary and said its addition was previously contemplated in its 2021 IRP. The utility said by the time it retires all its coal-fired generation in 2028, renewable energy will begin to dominate its energy mix, and it will need a source of flexible generation during peak energy use and extreme weather conditions in the winter and summer.

NIPSCO spokesperson Tara McElmurry said the utility requires a new gas-fired peaker to “support system reliability and resiliency, along with public safety, as part of a cleaner and more balanced energy mix for the future.”

“NIPSCO is committed to creating a reliable, sustainable supply of energy that will serve customers — both now and in the future,” McElmurry said in a statement to RTO Insider. The peaker will run only when necessary and act as a “bridge for the generation gaps of more intermittent energy sources.” She said NIPSCO’s goal to achieve net-zero carbon emissions by 2040 remains unchanged, and it will have the option to convert the plant’s fuel source to hydrogen in the future.

In testimony to the IURC, NIPSCO Vice President of Power Delivery David Walter said he is aware “some stakeholders would prefer that NIPSCO only implement renewable generation resources going forward.” However, he said that is not the most prudent option and that the plant will be “at least partially responsible for unlocking the long-term customer savings that are expected from NIPSCO’s overall generation transition.”

NIPSCO said its need for a peaking plant was emphasized through an updated portfolio analysis this year that “incorporated market shifts and changes” since its 2021 IRP. The utility included the effects of inflation, MISO’s new seasonal capacity market design and availability-based capacity accreditation, passage of the Inflation Reduction Act, and portfolio needs under the clean energy transition.

But Inskeep said NIPSCO shouldn’t be spending “exorbitant sums of ratepayer dollars to build more fossil fuel infrastructure that will hardly ever operate.” He said he is unconvinced NIPSCO needs a “massive expansion of natural gas” and that it did not adequately consider energy storage with grid-forming inverters, demand response or purchases from the MISO markets before it issued a request for proposals for thermal generation only.

NIPSCO maintains that using its existing facilities and some existing equipment at the Schahfer station will save customers money.

Inskeep also said CAC is “highly alarmed at the extraordinary expense” of the new units and the direction NIPSCO is taking on construction and financing.

NIPSCO rejected all three bids in response to its RFP. It was ultimately unable to land on an affordable engineering, procurement and construction agreement with an outside party, and plans to self-build the project.

Inskeep said the self-build prospect is a risky bet for ratepayers. He pointed out that, according to staff testimony, NIPSCO has not ventured into self-building a gas plant before. He also criticized NIPSCO’s plan to use CWIP, saying it is inappropriate for utilities to pass costs onto customers before they even incur them.

“Ratepayers will be paying for the gas turbines before they are used and useful, and even if they never generate any electricity. CWIP has a notorious reputation in utility ratemaking for harming ratepayers by shifting project risk from utility shareholders onto ratepayers,” Inskeep said.

NIPSCO can file to charge customers in advance of the project under a “clean energy” designation because the Indiana legislature passed a bill this year allowing utilities to use the financing option when they construct new natural gas plants that displace coal.

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ISO-NE Sees Little Shortfall Risk for 2032

There is little risk of energy shortfall in the summer of 2032, ISO-NE told the NEPOOL Reliability Committee (RC) on Tuesday, building upon the RTO’s previously released 2032 winter results that gave mixed signals on the system’s reliability.

ISO-NE told the RC the shortfall risk for the summer of 2032 appears to be similar to that of summer 2027. (See No Shortfall Anticipated for Summer of 2027, ISO-NE Says.)

“No energy shortfall was observed in any of the summer 2032 events; only one hour of 30-minute reserve shortfall was observed in one July 13, 1979, case and in one July 26, 1984, case,” Stephen George of ISO-NE said.

These results are part of ISO-NE’s ongoing “Operational Impacts of Extreme Weather Events” study, which the RTO developed in conjunction with the Electric Power Research Institute.

ISO-NE’s baseline winter 2032 analyses projected worst-case energy shortfall risk to decrease in 2032 compared to 2027 in most scenarios. However, a sensitivity analysis — which considered an additional range of factors — showed increasing risks for 2032 compared to 2027.

The baseline analysis indicated winter shortfall risks significantly decreased with the presence of the New England Clean Energy Connect (NECEC) transmission line, while the Everett Marine Terminal actually increased shortfall risk in most of the scenarios modeled. ISO-NE said it expects the 1,200-MW NECEC line to be in service by 2032, while the future of Everett remains in limbo. (See Narrow Set of Options for Retaining Everett LNG Terminal.)

“In terms of magnitude and probability, baseline studies of 2032 winter events indicate an energy shortfall risk profile similar to that of the 2027 winter event studies,” ISO-NE said in August about the 2032 winter modeling.

However, the RTO noted that the “sensitivity analysis of 2032 worst-case scenarios indicate an increasing energy shortfall risk profile between 2027 and 2032,” adding that the increased risk “is particularly observable with the 2023 CELT (Capacity, Energy, Loads, and Transmission) load forecast.”

The 2023 CELT forecast increased the projected electricity demand for the 2031/2032 winter by about 10% compared to the 2022 CELT projection. (See ISO-NE Increases Peak Load Forecasts.) The baseline analyses were run using the 2022 CELT data.

The winter 2032 sensitivity analysis used the worst-case weather event modeled in the baseline analysis, while varying the levels of resource retirements, electricity demand, imports, stored fuel inventories and forced outages. ISO-NE told the RC that sensitivity analysis results for the summer of 2032 will be shared at a future meeting.

These reliability findings come as ISO-NE grapples with increasing levels of variable renewable generation coupled with a massive expected increase in electricity demand stemming from electrification. ISO-NE expects the regional grid to transition from a summer peak to a winter peak at some point in the coming decades, in part because of heating electrification.

EMT, which is the only LNG import terminal in New England, is propped up by the expensive Mystic Agreement, which will expire after this winter. ISO-NE’s quantitative analyses have not shown that the terminal is necessary for grid reliability, but the RTO has maintained the facility may be needed in the future in the face of rising winter demand and reliability concerns.

“I think it would be extremely unwise were we to let that facility go until we know where we are with regard to these variables,” ISO-NE CEO Gordon van Welie said at a FERC forum on winter reliability in June. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.)

ISO-NE is conducting another round of sensitivity analysis for the winter of 2032, which will consider a range of factors and assumptions based on feedback from NEPOOL stakeholders. These added sensitivities will include varying levels of renewable generation, battery storage, behind-the-meter solar, demand response, imports, and gas, oil and nuclear resource retirements.

The RTO will discuss the results of this additional sensitivity analysis at the November RC meeting.

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ERCOT Expects Sufficient Capacity this Fall

ERCOT said Tuesday that it expects to have sufficient capacity to meet peak demand under normal conditions during the two-month fall season that begins in October.

According to the Texas grid operator’s fall seasonal assessment of resource adequacy (SARA), demand is expected to peak at 69.65 GW, a welcome relief after load averaged more than 80 GW over 227 hourly intervals during what has been brutal summer weather. The SARA indicates 99.73 GW will be available to meet demand in October and November.

That includes 3.99 GW of energy storage resources that have been invaluable in meeting record summer demand. A little over 1 GW of storage is assumed to be able to provide energy during the highest fall net load hours (total load minus wind and solar generation).

ERCOT said the estimated storage capacity is a proxy for what it expects during tight reserve hours and an interim availability assumption until a formal capacity contribution method is adopted in future SARA reports.

Solar energy, which played a key role during this summer’s tightest hours, is expected to contribute 11.66 GW during peak periods this fall with a 64% seasonal rating. Wind energy is expected to contribute 12.69 GW during those periods; it has seasonal capacity factors ranging from 31 to 41%.

The assessment includes a base scenario and three elevated and three extreme risk scenarios reflecting alternative assumptions for peak demand, unplanned thermal outages and renewable output. The most severe extreme risk scenario — a combination of high peak load, high unplanned thermal outages (more than 18 GW) and extreme low wind output — results in a high risk of rotating outages. An elevated risk scenario with low renewable output results in a capacity shortfall of 2.44 GW and close to a Level 1 energy emergency alert.

The grid operator said the SARA does not reflect pending changes that will come when the Texas Public Utility Commission approves a protocol revision (NPRR1176) that modifies the EEA level triggers.

The fall assessment marks ERCOT’s final SARA report. It is being replaced with what the grid operator calls the monthly operational assessment of resource adequacy (MORA). The revised report will be posted two months before the reporting month, beginning with the December assessment on Oct. 2.

The first MORA will be produced manually but will eventually transition into a multi-tabbed spreadsheet that will include a link to an interactive dashboard.

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NJ Offshore Wind Projects Face Whale Protection Measures

Two initiatives designed to protect marine life, specifically whales in one case, will shape the development of two New Jersey offshore wind projects as developers face rising public concern over the impact of coastal wind projects on tourism, commercial fishing and marine life.

The National Oceanic and Atmospheric Administration (NOAA) on Sept. 13 issued a series of rules under which the 1,100-MW Ocean Wind 1, the state’s first OSW project, could move ahead while also ensuring the “least practicable adverse impact on marine mammal species or stocks and their habitat.”

The rules limit when and how Ocean Wind 1 developer Ørsted can conduct certain activities, such as piledriving, exploding ordnance and other construction activities, and set out how the developer should look out for whales and monitor and report any activity that affects them. The rules are part of the agency’s Letter of Authorization that allows the project to go ahead with certain construction activities.

The rules package demonstrates how the impact of OSW projects on marine life has become a significant issue.

NOAA on Monday also announced the Biden Administration has set aside $82 million in funds from the Inflation Reduction Act to harness technology to “conserve and recover” the population of North Atlantic right whales, which face extinction in part because of collisions with ships and entanglement with ropes and nets.

In an unrelated move, Community Offshore Wind, which in August submitted a proposal for a 1.3-GW project in New Jersey’s third OSW solicitation, last week announced it has struck a “groundbreaking” five-year partnership with NOAA “to promote the exchange of data and expertise that will transform environmental monitoring for offshore wind projects.” (See NJ’s 3rd OSW Solicitation Attracts 4 Bidders.)

The developer, a joint venture between RWE and National Grid Ventures, said in a release that it will collaborate with NOAA on how to study the environmental impacts on the marine ecosystem, in part by increasing transparency and sharing expertise between researchers and developers.

“Our goal is to bring offshore wind energy monitoring activities into this partnership,” Jon Hare, director of the Northeast Fisheries Science Center, which is part of NOAA, said in the release. “This agreement is our first chance to make these partnerships a reality and show by example that effective scientific monitoring benefits everyone.”

Doug Perkins, project director for Community Offshore Wind, said he believes the scientific data would be “invaluable as we continue to study, and seek to mitigate, the impacts of offshore wind development on marine ecosystems.”

Shifting Public Perception

Concern over the impact of offshore wind projects on marine life, especially whales, has escalated since the start of the year as a number of dead whales — one press report said as many as 12 — have washed up on the New Jersey shore. Marine life supporters and opponents of the projects have seized on the deaths, suggesting that OSW development should be halted while investigators study whether there is a link between the deaths and preliminary ocean-floor studies conducted in preparation for the turbines’ construction.

State and federal investigators, including those for NOAA, say there is no evidence of such a link, and have outlined reasons why there wouldn’t be. (See NJ Legislators Probing Whale Deaths Hear No Clear-cut Conclusions.) One factor in the deaths isvessel strikes as whales increasingly move into areas that put them in the path of ships or take them into shallow waters near the shore looking for food, researchers say.

Maddy Urbish, head of government affairs and market strategy for Ørsted in New Jersey, said in response to NOAA’s issuance of the rules that “Ørsted prioritizes coexistence with our local communities, marine wildlife and ocean neighbors.”

“This permit strictly prohibits Ocean Wind 1 from seriously injuring or causing the death of any marine mammal and outlines mitigation measures the project will put in place including noise abatement, vessel speed and time of year restrictions, and dedicated observers aboard every vessel,” she said.

The rules set down by NOAA for Ocean Wind 1 were part of the agency’s issuance of an “incidental take” Letter of Authorization, which is required under the Endangered Species Act when a development activity potentially endangers the health of a protected species.

The rules establish “permissible methods” to provide for the “mitigation, monitoring and reporting” of conditions during the construction of Ocean Wind 1. Among the requirements are:

    • A seasonal moratorium on impact pile driving from Dec. 1 to April 30, the months of the greatest presence of North Atlantic right whales.
    • A requirement that ordnance detonation take place only during daylight.
    • A requirement that visual and passive acoustic monitoring be carried out before certain activities are conducted. The monitoring must be done by trained observers.
    • Training required for all Ocean Wind personnel to “ensure marine mammal protocols and procedures are understood.”
    • A delay to construction or ordnance detonations if whales or other mammals are spotted in the area. Pile driving must be shut down — “if feasible” — if a North Atlantic right whale is seen in the area.wha
    • A requirement that impact pile driving must be done with the “least amount of hammer energy necessary” and observers must continue to look for mammals for 30 minutes after any impact pile driving or ordnance detonation.

Whale Extinction

The rules give NOAA the right to withdraw or suspend a Letter of Authorization if a project does not “substantially” comply with the directives set out by the agency.

In the announcement Monday, NOAA said the $82 million in funds from the Inflation reduction Act would support the use of technologies such as “passive acoustic monitoring” and the development and implementation of other technologies to enable vessels to detect and avoid North Atlantic right whales and other large whales.

North Atlantic right whales are “approaching extinction” the agency said in a release, with only 350 such whales alive and fewer than 70 “reproductively active females.” The funds also will go to developing new technologies such as high-resolution satellite information to help monitor whale movement and understand whale distribution and habitat.

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Feds Release Road Map for Offshore Transmission Grid

Federal regulators on Tuesday issued a suggested road map for building out the transmission network needed for the thousands of wind turbines envisioned off the Northeast coast.

The departments of Energy and Interior presented “An Action Plan for Offshore Wind Transmission Development in the U.S. Atlantic Region” as a tool to boost the offshore wind sector, strengthen the domestic supply chain and create jobs while protecting the climate.

It suggests immediate actions to connect the first generation of wind projects to the onshore grid and longer-term efforts to continue growing the new energy sector for decades to come.

The Biden administration has set a goal of 30 GW of installed offshore wind generation by 2030. Subsequent federal goals and the individual goals of numerous states could push the total above 100 GW by 2050.

The Action Plan was shaped by a series of workshops with experts and stakeholders from early 2022 to early 2023 and by the forthcoming Atlantic Offshore Wind Transmission Study by DOE’s Wind Energy Technologies Office.

The Action Plan identifies increased intra-regional coordination, shared transmission lines and a network of offshore HVDC interlinks as priorities. To accomplish this, it makes a series of recommendations for industry; local, state and federal governments; and other stakeholders.

These include:

    • Before 2025: Establish collaborative bodies; identify steps to be taken, such as updating reliability standards and offshore-onshore interconnection points; create voluntary cost assignments and tax credits.
    • From 2025 to 2030: Convene and coordinate with states to plan an offshore transmission network; with industry to standardize HVDC technology requirements; and with tribes, state agencies, stakeholders and federal agencies on priority transmission paths.
    • From 2030 to 2040: Establish a national HVDC testing and certification center to ensure compatibility in the offshore grid network that is envisioned.

Offshore wind is one of President Biden’s signature initiatives, but it faced significant challenges even before the financial and supply-chain hurdles that began to threaten progress in 2022.

Central among these challenges, the Action Plan states, is that there is no offshore grid.

A disparate collection of stakeholders with competing interests must create an expensive new piece of infrastructure that can carry large amounts of electricity long distances in a harsh environment using facilities that do not yet exist with equipment and components that are in short supply.

They must navigate multiple regulatory processes in each of as many as four levels of review — local, state, federal and tribal — while protecting the marine environment, respecting coastal communities and minimizing conflict with other ocean users.

They must connect to an onshore distribution grid that already is vastly oversubscribed and is not standardized between regions.

Networked transmission might help with this, but such interregional efforts carry their own set of planning, ownership and cost allocation challenges.

Coordinated transmission is “notoriously difficult” to develop.

All of this demonstrates the urgent need for proactive and coordinated transmission planning along the Northeast U.S. coast, the Action Plan asserts. It identifies several specific shorter- and longer-term obstacles:

    • Near-term: Without a long-term planning vision, early projects using radial transmission lines could preclude future holistic transmission solutions; significant onshore upgrades will be needed to deliver the electricity coming off the ocean; siting is complex.
    • Mid- and long-term: Offshore transmission costs are high, and cost allocation mechanisms are inadequate; developing new policies, standards and practices may delay projects; strategic planning must replace unsustainable current interconnection practices; separation of generation and transmission creates a risk that one becomes a stranded asset while the other is being completed.

Spiraling costs have become an issue with offshore wind, as inflation and interest rates drive up development expenses that ultimately will be borne by the American public, whether through utility rates or taxes or consumer costs.

The price tag of the envisioned interstate offshore grid is unknown, but the Action Plan cites a telling estimate in a report completed by the Brattle Group on behalf of several environmental advocacy and clean energy industry groups: Proactive transmission planning for a future 100 GW offshore wind industry would save at least $20 billion.

A leading offshore wind industry group applauded release of the action plan Tuesday and highlighted the difficulty of the present-day development process.

“Rebuilding our transmission system is extremely complex, and the federal government can play a unique role bringing major parties together to break through barriers,” said Liz Burdock, CEO of the Business Network for Offshore Wind.

“Along with ensuring that we can develop our industry, building out the grid in a coordinated fashion will yield enormous benefits for ratepayers and the environment, build confidence in the market’s trajectory and accelerate development. We welcome the release of this action plan and encourage the federal government to begin working to bring states and stakeholders together.”

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DOE Reports Examine Difficult Job of Industrial Decarbonization

The U.S. Department of Energy on Monday released three “Pathways to Commercial Liftoff” reports focused on industrial decarbonization.

One report is focused broadly on industrial decarbonization, addressing chemicals, refining, iron and steel, food and beverage, cement, pulp and paper, aluminum and glass.

The other two focus on specifically cutting emissions in cement production and the chemicals and refining industries.

“This administration is committed to engaging with our private sector partners to accelerate the commercialization and deployment of key technologies needed to achieve the President’s ambitious climate and decarbonization goals,” Energy Secretary Jennifer Granholm said in a statement. “The reports released today provide in-depth analysis of emerging technologies and clear benchmarks to help guide targeted investments and propel the U.S. toward our clean energy future.”

Decarbonization presents an opportunity to transform industrial systems to improve energy and environmental justice, DOE said. Carbon-intensive industrial sectors are facing a critical inflection point, which offers a unique moment that neither the agency nor the private sector can allow to pass, it said.

The industrial sector represents 23% of the nation’s total greenhouse gas emissions, but the specific industries make up 14% of those emissions. Chemicals and refining is by far the largest emitting sector, making up 7% of the total U.S. emissions.

“Reasons often cited for slow progress on the decarbonization of industrial emissions include: the immaturity and high cost of many decarbonization levers; unidentified or uncertain customer demand for low-carbon products; and, in some but not all sectors, reluctance among companies to be a first mover,” the report said.

Even if the electricity and transport sectors decarbonize in line with the administration’s targets, and only limited abatement occurs in the industrial sector, the share of industrial emissions could rise to 27% of the country’s total by 2030 — even with associated impacts from the use of electricity and transportation.

The Infrastructure Investment and Jobs Act and the Inflation Reduction Act both offered support for decarbonizing industry. Customers and other stakeholders increasingly expect companies to address climate change, and some industrial firms are starting to work on it.

“Willing U.S. industry participants could utilize the momentum of the present moment to accelerate the commercialization of decarbonization technologies, respond to rising global demand for clean industrial commodities  and establish the U.S. as a global leader in industrial decarbonization,” the report said.

The report found that up to 30-40% of the emissions across the eight sectors could be addressed by 2030 using techniques that have net positive economics (when federal incentives are factored in), alongside emissions reductions from external factors such as cleaner grid power and transportation.

Ready-to-go decarbonization techniques include energy management systems/efficiency, carbon capture and storage (CCS) for natural gas processing, and other industry-specific changes.

“Expanding beyond near-term thinking and fully decarbonizing industry will be extremely challenging without cost reductions, education, breakthroughs, a complementary skilled workforce and widespread public acceptance,” the report said.

Another tranche of decarbonization would require some funding to bring demonstration-level technologies to the mainstream, such as industrial CCS retrofits, clean onsite electricity and storage and using heat pumps to electrify pulp and paper manufacturing.

However, to fully decarbonize all the industrial sectors in the report, some technologies that are  in the research and development or pilot phases will need to mature. Those include alternative chemistries to make cement and using captured carbon for industrial purposes.

The report estimates that fully decarbonizing the sectors it studied would cost between $700 billion and $1.1 trillion by 2050.

“To achieve adoption at scale of deployable technology levers will require bold leadership, even for solutions with net-positive economics,” the report said. “One factor is that, across the sectors of focus, many companies face pressure to plan towards and achieve near-term earnings targets.”

The report noted that environmental, social and governance (ESG) investing has been on the rise, which, along with “patient” capital, has somewhat alleviated that pressure, but the short-term focus on quarterly profits can still affect decision-making when it comes to making decisions on how to use long-term infrastructure investments.

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Idaho PUC Declines to Join Western RTO Governance Effort

The Idaho Public Utilities Commission last week said it will not join with other state regulators in an initiative to lay the groundwork for an independent RTO designed to serve the entire Western Interconnection.

Regulators from Arizona, California, New Mexico, Oregon and Washington proposed the West-Wide Governance Pathway Initiative in July in the face of increased competition for members between CAISO’s Extended Day-Ahead Market (EDAM) and SPP Markets+.

The proposal is intended to increase the potential for establishing a single wholesale electricity market that would include the participation of CAISO and build on the ISO’s existing Western Energy Imbalance Market and EDAM, for which the ISO recently filed a tariff with FERC. (See Regulators Propose New Independent Western RTO.)

Backers of the initiative issued an open letter Aug. 29 inviting stakeholders in the Western U.S. and Canada to build “Phase 1” of the effort, which will include “deciding on the form, mission and scope of an entity with independent, West-wide governance.” (See Backers of Independent Western RTO Seek to Move Quickly.)

But in a press release Thursday, Idaho regulators said they had voted unanimously not to participate.

Among their concerns was the conclusion that the initiative “has been less than transparent concerning its creating and funding.” The Aug. 29 letter stated that work on the initiative would be backed by “funding derived exclusively from 501(c)(3) sources,” an arrangement that would “be evaluated over time and will likely require supplementation as the workload intensifies.”

The Idaho commissioners said also that “there is no evidence that the initiative’s goal of independent governance is feasible without changes in California’s legislation,” an issue which has long impeded CAISO’s efforts to expand into the wider West.

The regulators additionally called the initiative’s goal of seating a board of directors by January 2024 “premature and unrealistic” and said that “at its core, the initiative presumes economic benefits for Western states without justification or specifics.”

Idaho PUC President Eric Anderson | Idaho PUC

“As always, the IPUC respects other commission, state and stakeholder decisions concerning participation with the initiative,” Idaho PUC President Eric Anderson said in the release. “However, given the IPUC’s concerns, the inherent flaws in the creation of the initiative and the initiative’s current actions and goals, the IPUC does not see a viable path forward for the initiative or that participation would result in any specific net economic benefits for Idaho customers.”

The governance initiative was the key topic during a panel discussion among utility commissioners at CAISO’s EDAM Forum in Las Vegas on Aug. 30. The commissioners acknowledged that Phase 1 would operate outside of any existing organization or decision-making process, and they asked regional stakeholders to provide feedback on how to structure the process.

Speaking on the panel, California Public Utilities Commission President Alice Reynolds said the effort is intended to set aside the problem of CAISO’s governance and determine what an independent entity “needs to look like.”

During a separate panel at the forum, Idaho Power CEO Lisa Grow lauded CAISO’s efforts in developing the EDAM but questioned the need for the West to create a full RTO in the near term.

Grow said that, unlike utilities in Colorado and Nevada, Idaho Power doesn’t “have legislative or PUC-mandated things that we have to do towards an RTO, so we can kind of watch how this goes.”

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Maryland Moves Ahead with Advanced Clean Car and Truck Rules

Maryland upped the ante on its clean transportation programs Monday as the state finalized its adoption of California’s Advanced Clean Cars II (ACC II) rule and began the process for adopting California’s Advanced Clean Trucks (ACT) rule.

Maryland is the eighth state to adopt ACC II, which will require all new light-duty vehicles sold in the state to be zero emission by 2035.

Gov. Wes Moore (D) announced the state’s intent to adopt ACC II in May. The rule could go into effect as early as January 2026, depending on when automakers begin rolling out their 2027 models, according to a spokesperson for the Maryland Department of the Environment (MDE). For the 2027 model year, 43% of new light-duty vehicles will have to be zero emission, with the share increasing between 6 and 9% per year, reaching 100% by the 2035 model year, according to MDE. (See Maryland to Adopt California’s Advanced Clean Cars II Rule.)

Both electric and hydrogen fuel-cell vehicles are classified as zero-emission vehicles. In addition to California, other states that have adopted the rule include Massachusetts, New York, Oregon, Vermont, Virginia and Washington.

Environment Secretary Serena Coleman McIlwain called Maryland’s adoption of ACC II “a big step toward cleaner air and a more aggressive response to the threats posed by climate change.”

MDE began the process for ACT adoption with a notice of proposed action, requiring truck manufacturers to increase the percentage of new zero-emission trucks sold in the state from 2027 to 2035.

MDE will hold a virtual public hearing on the proposed rule at 10 a.m. Oct. 11. Written comments may be submitted through Oct. 11.

The rule’s targets for clean truck sales vary depending on the type or class of truck. The percentage for Class 2b and 3 trucks, which include vans and heavier pickup trucks (8,501-14,000 pounds), would start at 15% in model year 2027 and rise to 55% by 2035. For heavier-duty Class 4-8 trucks (14,001-80,000 pounds), the zero-emission requirement would be 20% in model year 2027 and 75% in 2035.

MDE’s proposed rule on ACT was mandated under the Clean Trucks Act (H.B. 230) passed by the General Assembly and signed into law by Moore in April. If the proposed rule is finalized, Maryland would be the ninth state to adopt ACT, joining California, Colorado, Massachusetts, New Jersey, New York, Oregon, Vermont and Washington.

Both rules are expected to significantly affect transportation sector greenhouse gas emissions, which account for about 40% of the state’s GHG emissions, according to MDE. By 2035, ACC II is expected to cut carbon dioxide emissions from light-duty vehicles by 63% under 2021 levels, while nitrogen oxide emissions could drop 75% and sulfur oxides 64%, according to an analysis from the Sierra Club.

‘Commonsense Rules’

Special provisions of the Clean Air Act have made it possible for California to enact clean car and truck rules that exceed the vehicle emission standards set by the U.S. EPA. During the administration of former President Donald Trump, EPA revoked the Clean Air Act waiver allowing California’s stricter rules. Under President Joe Biden, EPA reinstated the waiver in March 2022, opening the door for California and other states to adopt ACC II and ACT.

The states that have adopted ACC II will be ahead of Biden’s goal for 50% of new light-duty vehicle sales to be zero emission by 2030.

Environmental and electric vehicle advocates were quick to provide statements of support for Maryland’s adoption of ACC II in a joint press release.

“Every day, fossil fuel cars emit pollutants that intensify climate change and contribute to toxic air pollution,” said Kevin Shen, policy analyst for the nonprofit Union of Concerned Scientists. “By adopting the Advanced Clean Cars II standards, Maryland has chosen to lean into its ambitious climate goals and jumpstart the transition to electric cars, which … will only continue to become even more efficient as Maryland cleans up its grid.”

Tom Van Heeke, senior policy advisor for EV manufacturer Rivian Automotive, called the ACC II standards “commonsense rules to expedite EV adoption in the state of Maryland …  especially if combined with the Clean Trucks Act of 2023.”

Ramon Palencia-Calvo, director of the Maryland League of Conservation Voters’ Chispa Maryland program, which is focused on Latino communities, stressed the public health impacts of the new standard.

“Communities of color, low-income communities and neighborhoods near major transportation hubs bear an especially unfair burden of harmful pollution due to decades of systematic marginalization,” Palencia-Calvo said. “Increasing the number of clean vehicles on our roads will reduce respiratory illness and hospitalizations, leading to healthier outcomes.”

Maryland at NYC Climate Week

The actions on clean cars and trucks came as Maryland officials sought to raise the state’s profile as a leader at Climate Week in New York City.

On Monday, MDE announced the state had joined the international Under2 Coalition, with Environment Secretary McIlwain signing the membership agreement. The coalition includes 167 state and regional governments committed to reaching net-zero emissions by 2050. Montgomery County joined the group in 2017, according to the Under2 website.

Joining the coalition “accelerates climate action in Maryland by giving us greater access to technical support and the shared knowledge of more than 160 governments across the world,” McIlwain said. “This action underscores our commitment to building the green economy that will dominate the next century, as well as creating the resiliency to make our state stronger.”

Maryland also is part of the Regional Greenhouse Gas Initiative, a regional cap-and-trade program, and the U.S. Climate Alliance, a bipartisan group of 25 governors committed to meeting the goals of the 2015 Paris climate accords.

Passed in 2022, Maryland’s Climate Solutions Now Act (S.B. 528) sets a 2031 target for the state to cut its greenhouse gas emissions by 60%.

Speaking at the Climate Week opening ceremonies Sunday, Moore made the case for centering climate action on community economic development, especially for low-income and disadvantaged communities.

“Our communities of color — our working parents — our middle-class families: They are the ones who stand to benefit most from our aggressive climate goals. Those are the hands that will install new solar panels at the local rec center. Those are the minds that will invent next-generation wind turbines that power millions of homes,” Moore said.

“This is about whether or not we can dominate industries of the future, instead of relying on industries of the past,” he said. “This is about whether or not we can bring manufacturing jobs home, instead of relying on foreign labor. This is about whether or not the clean energy revolution will close the wealth gap, instead of being just another way to make it bigger.”

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Calif. Sues Oil Majors over Climate Impacts

California is suing five of the world’s largest oil and gas companies, saying their executives have known for decades about the dangers of fossil fuels but hid the information to protect their profits.

The lawsuit was filed in San Francisco County Superior Court and announced over the weekend by Gov. Gavin Newsom (D) and Attorney General Rob Bonta.

The defendants are Exxon, Shell, Chevron, ConocoPhillips and BP and their subsidiaries, along with the American Petroleum Institute (API), a group representing the natural gas and oil industry in the U.S.

The lawsuit accuses the companies of “creating, contributing to and/or assisting in the creation of state-wide climate change-related harms in California,” including extreme heat, drought, wildfires, storms and flooding.

It asks the court to order the oil companies to pay for the impacts their actions have had on the environment, fine them for their alleged lies and award punitive damages.

“For more than 50 years, Big Oil has been lying to us — covering up the fact that they’ve long known how dangerous the fossil fuels they produce are for our planet,” Newsom said in a statement. “California taxpayers shouldn’t have to foot the bill for billions of dollars in damages.”

Cities and counties in California have filed similar lawsuits against fossil fuel companies for their alleged contributions to climate change. But with the state’s action, California has become the largest geographic area and the largest economy to sue big oil companies, the attorney general’s office said.

API responded to the lawsuit Monday by calling it “an enormous waste of California taxpayer resources.”

In a statement, API Senior Vice President and General Counsel Ryan Meyers said the industry provides “affordable, reliable American energy to U.S. consumers while substantially reducing emissions and our environmental footprint.”

“This ongoing, coordinated campaign to wage meritless, politicized lawsuits against a foundational American industry and its workers is nothing more than a distraction from important national conversations,” Meyers said.

Internal Memo Cited

Bonta said in a statement that oil and gas companies “have privately known the truth for decades — that the burning of fossil fuels leads to climate change.”

For example, the lawsuit cites a 1978 internal Exxon memo saying that “current scientific opinion overwhelmingly favors attributing atmospheric carbon dioxide increase to fossil fuel consumption.”

“Present thinking holds that man has a time window of five to 10 years before the need for hard decisions regarding changes in energy strategies might become critical,” the memo said.

But publicly, the companies were telling a different story, the lawsuit alleged. It pointed to a 1996 publication from Exxon called “Global Warming: Who’s Right? Facts about a debate that’s turned up more questions than answers.”

Then-Exxon CEO Lee Raymond said in the document that “taking drastic action immediately is unnecessary since many scientists agree there’s ample time to better understand the climate system.”

“Directly contradicting Exxon’s own internal knowledge and peer-reviewed science, the publication ascribed the rise in temperature since the late 19th century to ‘natural fluctuations that occur over long periods of time’ rather than to the anthropogenic emissions that Exxon itself and other scientists had confirmed were responsible,” the lawsuit said.

The lawsuit accuses the companies of still deceiving the public, through ads that portray them as climate-friendly businesses.

In addition, the lawsuit alleges, the companies’ actions have slowed the development of alternative energy sources, while increasing the costs of responding to the climate crisis.

Taking Aim at Big Oil

With the new lawsuit, California continues to take aim at the oil industry from multiple directions.

Last year, the state banned the sale of gas-powered cars starting in 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

And in June, a new state law intended to combat price gouging at the pump took effect. After calling a special session of the legislature this year, Newsom signed the first-in-the-nation law, which gives state regulators the power to penalize oil companies for price gouging.

The law created the Division of Petroleum Market Oversight within the California Energy Commission. Last week, the commission introduced Tai Milder, the prosecutor who will lead the division.

The division will look for irregular or illegal behavior within the industry and refer any potential violations to the attorney general’s office. The CEC has also launched a dashboard with an estimated breakdown of gas prices and margins.

“Transparency and accountability are essential to protecting California consumers, and those principles will guide the work of this division every day,” Milder said in a statement following his appointment.

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NYISO Operating Committee Briefs: Sept. 15, 2023

Stability And Voltage Studies

The NYISO Operating Committee on Friday approved three studies aimed at helping the ISO alleviate congestion on its grid.

The ISO’s Central East and Total East interfaces study reports, and its Central East voltage limit study, each sought to identify areas of the grid in need of upgrades to ensure it operates reliably under several different demand and environmental conditions.

The first two reports updated the definitions of the transmission components that make up the Central East and Total East interfaces and examined the impact of adding new 345-kV lines to the interface.

The Central East voltage limit study evaluated the grid’s performance after the addition of several new lines and found that performance improved, allowing for an increase in the minimum level of energy loss that triggers contingency operations.

NYISO expects the new interface criteria to be integrated into grid operations following the deployment of updated models and software in October.

Shortage Pricing

The OC also approved manual revisions NYISO says would improve the accuracy of transmission shortage pricing by better reflecting the actual costs of relieving constraints.

The changes involve eliminating transmission constraint “relaxation” logic for facilities and interfaces that use a demand curve mechanism and introducing a six-step mechanism for those assigned a non-zero constraint reliability margin.

NYISO argued the revisions would reduce market inefficiencies by more accurately pricing the relief services that certain transmission projects provide to the grid.

The Business Issues Committee had approved the revisions the previous day. They are expected to become effective in October after the deployment of software updates.

August Operations Report

Aaron Markham, NYISO vice president of operations, informed the OC that August saw a peak load of 24,917 MW but that the summer’s peak load of 30,200 MW occurred due to a heat wave Sept. 17.

Markham noted that the heat wave resulted in appropriately 1,500 MW of unforced outages.

He said NYISO is investigating the cause of the outages but that it had sufficient resources.

Markham also said the ISO has added 3 MW of energy storage and 66 MW of behind-the-meter solar resources since last month.