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November 1, 2024

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MISO Postpones Meeting for More Analysis on Entergy Expedited Substation Work

MISO announced it’s pushing back a scheduled meeting to discuss three new substations proposed by Entergy for expedited treatment in the RTO’s annual planning cycle.

The grid operator said it needs the pause to conduct more analysis on the trio of expedited projects to serve new load interconnections near Jackson, Miss., before it can recommend the projects move ahead.

Entergy proposed three new substations for the fast-growing industrial area of Madison County in August. It sought MISO go-ahead to build two new 230-kV substations to serve 267 MW in load apiece and a 500/230-kV substation to cover 537 MW in new load.

Entergy wants to bring the 230-kV substations online by early 2025 and 2026. The utility envisions the 500/230-kV substation to be operational by mid-2027.

But MISO said the “size and complexity” of the new projects means it was forced to postpone its Sept. 22 South Technical Study Task Force meeting, where it was due to discuss study results with stakeholders. MISO studies expedited project requests for adverse impacts on its system.

MISO said its review uncovered transmission issues were the proposed substations to be built. The RTO said its expansion planning team now must work with affected transmission owners to resolve the issues and said it will schedule a new task force meeting once it can complete its review.

MISO has been fielding numerous and more complex out-of-cycle requests for projects that can’t wait to begin construction until the early December approval typically reserved for the MISO Transmission Expansion Plans (MTEPs).

The grid operator has said the surge in expedited project review requests means it needs to modify its expedited study procedures so its planners won’t be overwhelmed. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

MISO also said it expects load growth driven by large industrial and commercial interconnections to continue for the foreseeable future. (See MISO: Expect More Expensive Annual Transmission Packages.)

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Report Extols the Benefits HVDC Lines Offer the Grid

The U.S. is behind Europe in deploying HVDC transmission technology, according to a report released Tuesday by the Brattle Group and DNV for clean energy and transmission advocates.

“The Operational and Market Benefits of HVDC to System Operations” noted that 300 GW of HVDC capacity has been installed worldwide, with an additional 150 GW in the planning stages, most of it in the last decade. The report was sponsored by the American Council on Renewable Energy, Allete, Clean Grid Alliance, GridLab, Grid United and Pattern Energy Group.

“HVDC transmission has evolved dramatically over the last five to 10 years,” Brattle Group Principal and co-author Johannes Pfeifenberger said on a webinar hosted by ACORE. “HVDC offers higher capacity, longer distance [and] lower loss transmission on a smaller footprint, which really are key advantages.”

Connecting HVDC lines to the standard AC grid requires converters, and the newer voltage-sourced converters, which can be switched on and off by an external control signal — unlike the historically more common line-communicated converters that can only be turned on by an external signal — greatly enhance HVDC’s capabilities, Pfeifenberger said.

Europe has led the way in deploying modern HVDC technology with VSC converters recently, with about 50 GW of projects in operations and another 130 GW planned over the next 10 years. North America accounts for only 3% of the technology’s use and 30% of planned projects, most of which have been proposed by merchant developers.

“It’s pretty straightforward if you want to move power over long distance: DC is a much more efficient way to do that in terms of right-of-way cost and controllability,” said Grid United CEO Michael Skelly, whose firm has proposed a number of HVDC projects to connect the three interconnections.

In the mid-2000s, when Texas was considering the Competitive Renewable Energy Zone lines to bring wind power to market, they considered HVDC; Skelly said now there might be a “little bit of buyer’s remorse.” With how much growth ERCOT has seen in recent years, HVDC might make a comeback, he added.

The one domestic market the report highlighted as fully embracing HVDC technology is CAISO, with Pfeifenberger noting that the Trans Bay Cable in the San Francisco area is the first VSC HVDC project in the world.

“Because they were the first operator of a VSC-based HVDC line, the Trans Bay Cable, they really like the technology; they have optimized it into the market; they’re fully co-optimizing controllable transmission with generation in the day-ahead in real-time markets,” Pfeifenberger said. “They’re optimizing transmission across the entire West now. And they are developing a specific way to integrate merchant transmission lines into all this market optimization.”

The report is full of anecdotes about European countries starting to knit their grids together with new HVDC lines. Germany is linking up its wind-rich north and solar-rich south with major projects. Italy, which has HVDC subsea cables connecting Sicily and other islands, is now expanding its use similarly to its northern neighbor. Other examples abound around the continent.

HVDC works better than AC lines when it comes to burying transmission, said DNV Vice President and report co-author Cornelis Plet.

“Whenever power needs to be transported over more than 50 miles by underground cable or maybe 300 to 400 miles per overhead line, HVDC is the only technical, feasible option,” Plet said.

In addition to the ability to be out of sight, HVDC technology also requires a smaller footprint so it can help get transmission built in urban areas where new rights of way are very hard to procure, he added.

Another reason Europe has been building out so many lines is the growth of offshore wind, as DC lines can operate underwater. Now a major question on the continent is whether the HVDC lines should operate as single entities or be stitched together in an HVDC grid that overlays the AC system, Plet said.

One issue with the rapid growth in Europe is supply-chain concerns, as the manufacturing base — while currently sufficient — would be strained to try to meet an uptick in demand from North America as well, he added.

“The U.S. must build a similar project pipeline and, importantly, take advantage of the significant planning and operational experience that has already been gained with modern HVDC systems,” Plet said.

Another hurdle to getting HVDC or other major transmission needed to expand renewable power and address climate change is the current permitting process, said Rep. Sean Casten (D-Ill.), Congress’ chief FERC booster.

The lack of transmission is one of the two main problems with renewables, the other being that it “is too damn cheap,” Casten said on the webinar.

“You’ve generated this problematic resource that is super cheap: Whether it’s wind, whether it’s solar, you have effectively zero marginal cost,” Casten said. “And on the other end of that wire, you have a person or an entity — maybe it’s an RTO, maybe it’s a utility — who has an entire pile of assets that are dependent on earning $50, $60, $70/MWh, and you want to put $30 power into that market.”

That gives the entities who would receive that cheaper power a clear economic disincentive to do so, he added. The politics of defending high prices are not good, so opponents come up with spurious arguments like transmission causes “eagle cancer,” Casten quipped.

Casten and Rep. Mike Levin (D-Calif.) are working on a bill that seeks to be the Democrats’ opening position on transmission permitting. The two are trying to make sure the industry’s profit motive is aligned with transmission expansion to bring renewables to market, get the right participants in the planning process and then smooth out the siting and permitting processes.

“Let’s not make it harder to permit a transmission line than it is to permit a natural gas pipeline, which it is as long as we have only one authority responsible for one of those,” Casten said.

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Champlain Hudson Converter Station Breaks Ground in NYC

Two key pieces of New York City’s clean energy future are taking shape along the East River waterfront.

The converter station for the Champlain Hudson Power Express and the Brooklyn Clean Energy Hub both hosted ceremonial ground-breaking ceremonies in the past week.

Both will play an important role in keeping the lights on in the city, but the need is more pressing for the CHPE facility in the Astoria neighborhood of Queens. NYISO has warned that further delays in the transmission project could worsen the reliability margin deficit the city faces starting in 2025.

Gov. Kathy Hochul (D), U.S. Department of Energy Deputy Secretary David Turk, Premier of Quebec Francois Legault and dozens of other officials gathered Tuesday to mark the start of work on the project.

CHPE is a 339-mile underwater and underground HVDC line that will carry up to 1,250 MW of power generated by Quebec hydropower plants to New York City. After more than a decade of planning and review, construction of the line began early this year.

Now, work has begun on the converter, which will occupy a former fossil fuel site. Six tanks that once held 12 million gallons of No. 6 oil were removed in the weeks before Tuesday’s event, along with nearly four miles of piping.

Hochul said in a news release: “The transformation of a fossil fuel site into a zero-emission facility highlights the world of possibilities we have to reduce our dependence on fossil fuels, mitigate the impact of climate change and accelerate our collective progress of shifting our power grid to go green.”

New York Gov. Kathy Hochul speaks Tuesday at the site of the Champlain Hudson Power Express converter station under construction in New York City. | New York Governor’s Office

CHPE also will move New York state closer to its 2030 goal of 70% renewable power generation and will help fill the gap created by the mandated peaker plant retirements that NYISO has warned will create a deficit.

“The importance of the Champlain Hudson Power Express project to maintaining grid reliability and enabling the transition to the grid of the future cannot be overstated,” NYISO President Richard Dewey said in a news release. “By delivering 1,250 megawatts of clean, renewable hydropower to the New York City metro area, this project plays a key role in the move to electrify the economy and meet the state’s ambitious clean energy goals.”

Seven miles south, in Brooklyn’s Vinegar Hill neighborhood, Con Edison broke ground Sept. 12 on its Clean Energy Hub.

The facility eventually could serve as the interconnection point for up to 1,500 MW of the 9 GW of offshore wind power that New York state hopes to have online by 2035.

But there already is a pressing need for the Clean Energy Hub as a means of maintaining reliability, because the surrounding area is placing greater demand on the grid with electrification of buildings and transportation.

Con Edison expects demand in certain neighborhoods to exceed the existing infrastructure’s capacity by 2028.

“The Brooklyn Clean Energy Hub represents a major milestone in the clean energy transition and will strengthen our grid’s reliability,” Con Ed CEO Tim Cawley said in a news release. “This project will offer a critical plug-in point to connect with offshore wind, while creating good jobs, supporting economic growth and advancing New York’s climate goals.”

The CHPE station stands in an area with multiple fossil-fired generating stations and resulting poor air quality. Con Ed’s Hub also occupies the site of a former fossil-fire facility.

Neighborhood activists cheered the conversions.

Costa Constantinides, CEO of Variety Boys and Girls Club of Queens, said: “Today is a great day for the energy transition away from fossil fuels here in Astoria. For too long our community has borne the brunt of fossil fuel production and the health impacts that have turned our neighborhood into ‘Asthma Alley.’”

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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.”