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November 14, 2024

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NY Offshore Wind Transmission Project Draws No Residential Comment

The first-ever offshore wind transmission project in New York will bring 816 MW from Empire Wind 1 right under Brooklyn streets — and has drawn no comment from local residents (21-T-0366).

Siting major new energy infrastructure in New York City is notoriously difficult and expensive. Equinor (NYSE:EQNR), which is managing the project on behalf of itself and partner BP, will likely pay half a billion dollars or more to lay 17.4 miles of twin submarine cables in state jurisdictional waters. But it is facing no opposition to its plans to bring the 230-kV lines ashore at the South Brooklyn Marine Terminal.

Only developer representatives, labor and industry interests, and academics spoke at a public hearing hosted by the New York Public Service Commission on Tuesday.

According to Mariah Dignan — regional director on Long Island for Climate Jobs New York, a statewide labor coalition representing 2.6 million workers — the project and its related onshore work will undoubtedly serve the public interest and is necessary to meet the state’s climate action goals, especially the 9,000-MW target for offshore wind energy by 2035. Dignan made her remarks Tuesday.

“In addition, the project and related onshore work and construction must be done with good union, family-sustaining jobs,” Dignan said. “We look forward to working with the applicant to make this clean energy economy a reality through a just transition for not only our workforce but also our communities.”

The 50/50 joint venture of Equinor and BP (NYSE:BP) also includes Empire Wind 2 and Beacon Wind 1. The three projects will collectively provide 3.3 GW of electricity, Harrison Feuer, director of public affairs in the state for Equinor Renewables U.S., said in a presentation at the hearing before it opened to public comment.

Empire Wind Tx Proposal (Empire Wind) Content.jpgThe EW1 onshore export cables between the cable landfall and the onshore substation will consist of a three-core 230-kV HVAC bundle and are not expected to differ from the submarine export cables. | Empire Wind

 

The operations and maintenance base for all three projects will be situated in an industrial park adjoining the South Brooklyn terminal. “We do extensive environmental and social impact evaluations to minimize the effects on wildlife and local communities, and that happened long before we get started,” Feuer said.

The developers expect state permitting to conclude between the end of 2023 and beginning of 2024, when construction will then commence, said Joshua Verleun, Equinor manager for the permitting process in New York.

After landfall at South Brooklyn, the 230-kV export cables will be connected to an onshore substation to up the voltage to 345 kV for interconnection to the grid.

“When the cables make landfall, they will be pulled directly through the bulkhead to terminate into the onshore substation,” Verleun said. “From the onshore substation there is a short interconnection cable that runs along New York City streets and connects into the existing Con Edison Gowanus substation.”

The approval of the project’s transmission lines will be a critical milestone in its development, said Fred Zalcman, director of the New York Offshore Wind Alliance, a coalition of OSW developers, including Equinor, national environmental organizations, labor and academia.

“This project presents many good benefits to the electric grid of downstate New York, and one of the key benefits I see is its proximity to the New York City load center,” said Thomas Barracca, director of the Office of Economic Development at Stony Brook University, which runs a workforce development program for the OSW industry in New York. “In terms of environmental impact, the project has been very well conceived and thought out, and has obviously been vetted with a lot of stakeholders in the environmental community.”

The developers engaged with local fisheries, whose feedback helped inform decisions on how the project is made, and also worked closely with the U.S. Bureau of Ocean Energy Management and Department of Defense to mitigate any potential interference of coastal defense and radar, Feuer said.

“We are delighted that the cable connection would be going to Brooklyn,” said Adrienne Esposito, executive director of Citizens Campaign for the Environment, a statewide group with 140,000 members. “We all know that the greatest load of fossil fuel use is … in New York City and also on Long Island, and that’s why it’s so imperative that wind farms get connected to both of those areas.”

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NY Greenlights $345M, 280-MW Excelsior Solar Farm

New York officials on Wednesday approved a NextEra Energy Resources subsidiary to build and operate a 280-MW solar farm with 20 MW of battery storage capacity on a few thousand acres of farmland between Rochester and Niagara Falls (19-F-0299).

The state Board on Electric Generation Siting and the Environment authorized a certificate of environmental compatibility and public need for the estimated $345 million Excelsior Energy Center project in the Town of Byron in Genesee County. The facility will be the largest solar farm ever built in New York, with solar panels covering 1,716 acres on a project tract of about 3,443 acres and is expected to begin commercial operation in late 2022.

Administrative Law Judge Gregg Sayre detailed the reasoning of the Department of Public Service staff recommendation to the siting board, saying the contested issues fell into three areas: the use of agricultural land, particularly prime farmland; the impact of the project on the character of the community as a result of its size and visual impact; and the alleged noncompliance of the project with the Town of Byron and Genesee County comprehensive plans.

Contested Issues

The state Department of Agriculture and Markets objected to 30% of the project being located on prime farmland and claimed that a solar energy project constitutes a permanent conversion of farmland to non-agricultural uses.

The Siting Board rejected the argument about permanent conversion of farmland in the Hecate Energy Albany case in January of 2021 when it concluded that a commercial solar facility does not result in a permanent loss of farmland where certificate conditions require the land to be fully restored as closely as possible to its prior condition upon decommissioning (17-F-0617).

Gregg Sayre (NYDPS) Content.jpgJudge Gregg Sayre, NYDPS | NYDPS

“In this case there is some permanent loss of farmland due to access roads and other similar construction, but it amounts to only about 31 acres, which is less than 1% of the project’s area,” Sayre said. “Although the department is certainly correct that agricultural production will be reduced in the footprint of the project for approximately 30 years, the reason behind that loss is that the property owners in question have voluntarily entered into lease agreements with the applicant.”

A local group, Byron Association Against Solar (BAAS), filed at least 20 documents regarding safety concerns, issues concerning soil and air contamination, concerns about the danger of battery fires, and the layout of the project, roads, boundaries and set-backs.

BAAS offered two studies to support its position that the project will have a massive negative impact on farming in the town of Byron, but one of the reports was based on what Sayre said is a “completely erroneous” number of affected acres. The report, he said, is deficient in using one year of crop pricing in its analysis of impacts rather than a longer average given the price fluctuation that occurred over the course of several years in the town’s top 10 crops.

The second study produced by BAAS claims that the project would cause a redistribution of farms and lands and an increase in farming costs, but it fails to support its conclusions that the project would increase the cost of farming in the area, Sayre said.

BAAS also put in the testimony from Eric Zuber, owner of a large dairy farm adjoining the project area, who stated that he would lose the use of farmland on which he spreads excess manure.

Secondly, the order concluded that claims that the project will destroy the rural community were “overstated” and that visual impacts have been avoided or minimized to the maximum extent practicable.

Laws and Plans

The third issue in dispute was based on the testimony of a local resident speaking for himself, not for the town or the county, that the project is inconsistent with the town and county comprehensive plans.

Tammy Mitchell (NYDPS) Content.jpgTammy Mitchell, NYDPS | NYDPS

“The resident is absolutely correct in stating that the protection of agricultural lands is listed as a goal in both of those plans, but … the town comprehensive plan also explicitly supports the development of clean energy resources, so there is necessarily, as with most land-use issues, some balancing required of competing goals,” Sayre said.

Last year, the town adopted a solar law, finding that the law is consistent with its comprehensive plan, and the county planning board implicitly found that the law was consistent with both the town and county comprehensive plans when it approved the town law, Sayre said.

“I believe that the proposed draft order granting a certificate of environmental compatibility and public need for the Excelsior solar generating facility is well balanced and avoids or mitigates impacts to the extent practicable,” said Tammy Mitchell, director of the DPS Office of Electric, Gas and Water, serving as alternate chair of the board in place of Public Service Commission Chair Rory Christian.

The other alternates for the permanent members of the Siting Board were Louis Alexander, representing the commissioner of the Department of Environmental Conservation; Dr. Elizabeth Lewis-Michl, representing the commissioner of the Department of Health; Vincent Ravaschiere, representing the commissioner of the Department of Economic Development; and John Williams, representing the chair of the New York State Energy Research and Development Authority.

The Siting Board for the Excelsior case also included one ad hoc member, Norman Pawlak, dissenting.

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California Seeks to Blaze Trail for Long-duration Storage

California Gov. Gavin Newsom is looking to earmark $380 million for long-duration energy storage (LDES) incentives in his proposed 2022/23 state budget. For California energy officials, the state’s grid operator and LDES developers, that money can’t arrive soon enough.

California defines “long-duration” as any storage resource able to discharge energy to the grid for at least eight hours at full output, but the state also has a “stretch goal” of 20 to 100 hours. While otherwise technology-neutral, Newsom’s incentive program would seek to boost the commercial prospects of alternatives to lithium-ion batteries and pumped hydro. Priority would be given to technologies on the verge of commercialization or positioned for widespread deployment within the next five to 10 years.

Speaking Tuesday at an interagency workshop exploring ways to advance the adoption of non-lithium-ion LDES, California Energy Commission Chair David Hochschild acknowledged that the $380 million in funding “still has a little ways to go” before passing the legislature.

“But part of the reason for coming together today was feeling an incredible sense of urgency about getting this right, particularly on program design,” Hochschild said.

Two issues are driving that urgency, according to speakers at the workshop.

The first is that California’s grid, increasingly reliant on variable renewable generation, will soon push its reliability limits by relying on four-hour batteries as a substitute for gas-fired peaking resources.

The second factor is more global in nature, with competition for worldwide lithium supplies heating up as more consumers purchase electric vehicles and government policies across the world encourage the electrification of most forms of transportation and heavy-duty equipment.

‘Incredibly Versatile’

Two years ago, CAISO had about 200 MW of battery storage on its grid. Today it manages 3,100 MW, most of which is lithium-ion. By summer, that number is expected to reach 4,000 MW.

During Tuesday’s workshop, Hochschild praised the state’s ability to integrate that kind growth in such a short time.

“We’re not finished, of course; there’s a lot more to go; but just to actually have that installed and dispatchable is incredible,” he said.

“Not only is California leading the way in terms of [storage] technologies that are on the grid, and what we’re operating today, we’re also leading the way in terms of the tools that we have to actually manage and operate these resources,” said Gabe Murtaugh, storage sector manager at CAISO.

California’s battery storage resources, predominantly four-hour in duration, are “incredibly versatile,” helping CAISO manage peak loads and “operational uncertainty” on the grid, Murtaugh said. The ISO has committed much time to developing market models that manage the state of charge of those resources, he said, ensuring they’re available when needed most, such as on the hottest summer days.

But the continued emergence of storage requires a dynamic approach to managing the resources, Murtaugh said. The California Public Utilities Commission’s 2032 integrated resources plan calls for 15 GW of storage by 2032, with 30 to 50 GW looking further out, according to Jonah Steinbuck, deputy director of the CEC’s Energy Research and Development Divsion.

“Just because we have a model that works today, and we’re sharing that model with other ISOs and RTOs across the country, doesn’t mean our work on storage is done by any means,” Murtaugh said. “We know that there’s other different kinds — different flavors — of technology: long-duration technology; other short-duration batteries as well. And as we’ve mentioned before, the ISO is technology-agnostic, so we really need to design our models to be able to accommodate all kinds of technologies potentially.”

The growing prevalence of variable generation in California will alter the shape of CAISO’s “duck curve,” the iconic graph that depicts the deep trough in the ISO’s “net load” during the middle of the day (formerly the period of peak demand) as solar resources reach full output, followed by the steep rise in net load heading into evening as those same resources taper and cease production.

Longer-term peak load forecasts from the CEC indicate the middle of the duck curve will become even deeper and wider as California brings on more solar resources, while net loads in the late afternoon and evening will become even steeper with increased electrification of the state’s economy.

The key for the ISO is to shift the solar oversupply in the trough period to the high needs during the ramp. Using the CEC’s forecasts, CAISO predicts that, by 2024, four-hour batteries discharging at full capacity will be insufficient to provide the energy flows necessary to meet demand across a longer and steeper evening peak. Long-duration storage will be needed to cover that gap and avoid continued reliance on peaking plants.

“Obviously, you can take a four-hour battery and operate it at something less than its full output for a longer period of time, but you’re probably losing some efficiency there,” Murtaugh said.

More challenges loom beyond 2024, as the state pursues its policy of achieving a zero-emissions grid by 2045, requiring use of even longer-duration storage of up to 100 hours, Murtaugh said. That’s because CAISO expects the grid will shift from a summer- to winter-peaking system.

“The hardest times will be during multiday periods when we have low wind and low solar availability, which is more prevalent in the winter than it is in the summer,” he said. “And in those kinds of situations, when we’re very heavily reliant on renewables to produce the energy that’s going to be consumed in the state, then you need storage or some other solution to generate new energy in order to keep the lights on across those periods.”

Other factors will compound the need to adopt long-duration storage by the middle of this decade, according to James McGarry, a senior analyst in integrated resource planning at the CPUC.

Among them is the expected retirement in 2024 of 1.3 GW of gas-fired capacity 40 years or older and the closure of 3.7 GW of thermal plants relying on once-through cooling, followed by the 2025 retirement of the 2.3-GW Diablo Canyon nuclear plant.

“And throughout this time period, West-wide heat and drought conditions paired with neighboring states increasing their own clean energy commitments are leading us to expect tighter availability of imports during peak demand periods,” McGarry said.

“As we look across different use cases and applications, long-duration storage has a major role to play in the ISO’s local capacity requirements,” said Jin Noh, policy director for the California Energy Storage Association. “Studies are already showing a significant need to look at long-duration storage if we really want to replace local gas generation.”

Noh said long-duration storage could provide more of the “diverse capabilities” the ISO is seeking to manage a system increasingly dominated by inverter-based resources, including offering inertia support and helping to “better optimize and utilize the other resources on the grid.”

‘Dirt Cheap’

According to Noh, long-duration storage technologies already benefit from “pretty significant” private investment. But Gov. Newsom’s proposed incentives would “serve as that tipping point for technologies that are really on the verge of commercialization” while easing the “first-mover burden” on those organizations adopting the new technologies.

CEC Vice Chair Siva Gunda pointed out that part of that burden includes testing — then rapidly scaling — the new technologies. Lithium-ion batteries benefited from about 10 years of deployment and providing operational data before attracting broad private investment, he said.

To help alleviate the proof-of-concept burden for LDES, the U.S. Department of Energy has proposed the Rapid Operational Validation Initiative, designed to accelerate testing and have resources ready for commercialization by 2030, ahead of the Biden administration’s 2035 target for a clean U.S. electricity system, said Eric Hsieh, DOE’s director of grid systems and components.

“We’re looking to use these demonstrations to collect data from them [and] combine them with accelerated testing procedures in the lab with domain knowledge and [artificial intelligence/machine learning] algorithms, with the intent of being able to provide investment-grade performance projections with just one year of data,” Hsieh said.

And another key development adds to the time pressure to deploy LDES, according to Larry Zulch, CEO of Invinity Energy Systems, a flow battery developer.

“I talk to a lot of metals companies, people who are in the trade, and they keep telling me, ‘You have no idea what kind of lithium shortage is coming along because of the [transportation sector] requirements,’” Zulch said.

Zulch said the applications that will rely on energy-rich lithium-ion batteries, which include EVs, airplanes and construction equipment, “far exceed the increased production capabilities” of lithium and nickel mines.

Invinity’s flow batteries rely on vanadium, which Zulch said is more abundant than copper and found throughout the world, preventing it from becoming a “conflict” mineral.

Other LDES company representatives speaking during a workshop panel also touted the relative abundance of the critical minerals used in their systems. Mateo Jaramillo, CEO of Form Energy, said his company’s iron-air design relies on the most heavily mined mineral on Earth, present on every continent. Henrik Stiesdal, founder of Stiesdal A/S, said the storage medium in his company’s thermal energy system is crushed basalt, which he called “dirt cheap.”

Unsurprisingly, company executives were unified in their belief that the moment has already arrived for LDES.

“I think the [LDES] batteries that all of the panelists, along with myself, are able to produce and provide are addressing a specific market need that’s already there,” said Balki Iyer, chief commercial officer of Eos Energy.

“What we see here is the fact that we actually have a longer-duration need from the market [that’s] driving the shift, moving away from lithium to non-lithium, longer-duration batteries,” he said.

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TVA Board Nominees Back Renewable Power, Affordability

Nominees to the Tennessee Valley Authority’s Board of Directors stressed affordable rates and a more robust renewable portfolio for the federal utility during their confirmation hearing Tuesday.

Beth Geer, Robert Klein and L. Michelle Moore appeared before the U.S. Senate Committee on Environment and Public Works about a year after they were nominated to the TVA’s board by President Joe Biden. Also sitting before the committee was Ben Wagner, a longtime employee in TVA’s office of the inspector general who has been nominated to serve as the federal utility’s next inspector general.

Committee Chair Sen. Edward Markey (D-Mass.) opened the hearing by saying TVA could do more to provide innovation, low-cost power, environmental stewardship, and reduce its 10 million customers’ energy burdens.

Markey said TVA could substantially expand its generation portfolio’s 3% share of wind and solar, both at the utility scale and the distribution level. He called the 3% share a “very sad number.”

“It’s almost as though it’s still the 1930s and there hasn’t been any real progress in terms of the implementation of real change,” Markey said. “Unfortunately, the TVA has pushed, for several decades, more fossil fuel energy at the expense of potentially cheaper renewable sources, which pollutes our communities and exacerbates energy burdens for TVA customers, who already pay some of the highest electricity bills in the nation as a percentage of household income.”

TVA nominees (US Senate Committee on Environment and Public Works) Content.jpgTVA nominees (from left) Beth Geer, Robert Klein, L. Michelle Moore and Ben Wagner | U.S. Senate Committee on Environment and Public Works

Markey said the trio of nominees are well-positioned to prudently influence the utility’s energy planning for years to come and provide customers with “reliable, clean and affordable” energy.”

However, ranking member Sen. Jim Inhofe (R-Okla.) said “calls to eliminate fossil fuels from the power sector are foolish and would be devastating for the American people by increasing already sky-high utility bills and creating greater unreliability for the electric grid.”

He said the nominees must recognize the ongoing need to maintain fossil fuels as part of TVA’s power supply.

“The TVA must not be weaponized to pursue a radical, Green New Deal-inspired agenda that forgoes reliability and affordability and fossil fuels for its power supply in the name of climate alarmism,” Inhofe said.

He also criticized the slate of nominees for not including anyone from Kentucky or Mississippi.

The TVA Act prescribes that seven of the board’s nine members be residents of the TVA service area and that their residences be geographically diverse across the footprint. The current board contains members hailing from Georgia and Tennessee; the nominees also come from those two states.

TVA’s current board is at quorum with five of nine seats filled. However, two directors’ terms expire in May. The utility’s bylaws allow board members to stay on through the end of the year to maintain quorum if replacements have not been confirmed in time.

The current board includes Chair William Kilbride, whose term expires in 2023; A.D. Frazier and Jeff Smith, whose terms expire this year; and Beth Harwell and Brian Noland, whose terms expire in 2024. If the nominees are confirmed, the board will have three women instead of one, but no one of color.

“The financial success of renewable energy is something I observe daily in my current work, and it’s why the sustainability revolution may now be the most significant investing and business opportunity in the world,” Geer said in her testimony. “Sustainability does not just make sense for our environment; it makes good sense for economic progress.”

Geer, a Tennessee resident, is chief of staff to former Vice President Al Gore and serves on Nashville’s Sustainability Advisory Committee.

“Let me say that while I have worked in the political realm at many points in my career, I firmly believe that doing what is best for all the people of the Tennessee Valley is what matters, and that is, at the end of the day, a non-partisan issue,” she said.

Geer said she shared Markey’s concerns with TVA’s relatively small deployment of wind and solar.

Ernst Objects to 2015 Tweet

Sen. Joni Ernst (R-Iowa) said she will oppose Geer’s nomination over a 2015 Twitter comment she made in response to a Fox News tweet featuring an image of Ernst and a quote from her State of the Union response. Geer responded “hideous” to the tweet, which asked, “What did you think of Sen. Joni Ernst’s GOP response to the State of the Union address?”

Ernst asked Geer to explain herself, saying, “You believe one reason you should be confirmed to serve in the TVA, the Tennessee Valley, is because of your ability to quote, ‘build relationships and work together,’ end quote. Is that correct?”

Beth Geer (US Senate Committee on Environment and Public Works) Content.jpgTVA board nominee Beth Geer | U.S. Senate Committee on Environment and Public Works

“Well, I apologize if I offended you, and I appreciate you bringing it to my attention,” Geer said. “And I do, in fact, believe that civility is key, and I’m sorry that I did not demonstrate that, in your opinion, with that tweet.”

Klein, a former lineman at the Electric Power Board of Chattanooga and member of the International Brotherhood of Electrical Workers, said TVA’s status as a government-owned public utility poises it “to be a leader in technology and innovation for the nation, allowing the United States and the Southeast, in particular, to contribute to our collective goals of decarbonization.”

Klein said if confirmed, he would support carbon reductions and “look for projects that could potentially lead the way in further reductions.” He said he was particularly interested in TVA’s exploration of a small modular nuclear reactor near Oak Ridge, Tenn.

Klein also said he was committed to exploring new renewable energy additions to TVA’s fleet.

Moore, a former sustainability staffer in the Obama White House and CEO of solar nonprofit Groundswell, said “energy and environmental quality go hand in hand in hand with fiscal responsibility” and pointed to her work in helping build a market for green buildings that use less energy and water.

She recalled a childhood in which her grandparents would rack up “backbreaking” $300-$400 energy bills because they were forced to turn on their furnace periodically during Georgia winters to keep their inefficient house’s pipes from freezing.

Ranking member Sen. Shelley Capito (R-W. Va.) grilled Moore on a 2018 tweet on her now-private, personal twitter account where she wrote, “Oil is like opioids, it keeps you sick and poor.” Capito asked how Moore would square her opinions with TVA’s 40% fossil fuel energy portfolio.

L Michelle Moore (US Senate Committee on Environment and Public Works) Content.jpgTVA board nominee L. Michelle Moore | U.S. Senate Committee on Environment and Public Works

Moore said while she was grateful for fossil fuels powering the Industrial Revolution and helping to lift families out of poverty, it’s time to move forward with clean energy and new technologies. She said she envisioned battery storage having a bigger role in TVA’s portfolio and said she will make sure that as TVA’s decarbonization plays out, communities with fossil plants will be supported.

Late last year, the five-member board voted to give TVA CEO Jeff Lyash more discretion over utility decisions, including replacing output from the Cumberland and Kingston coal plants in Tennessee. TVA is currently exploring building pipelines and two new natural gas plants at the sites, a move the Sierra Club opposes.

TVA’s emissions goals and renewable generation plans are currently the focus of an inquiry by the U.S. House of Representatives’ Committee on Energy and Commerce. The committee is questioning whether the utility is doing enough to keep rates affordable and invest in renewables and energy efficiency. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry.)

Before the inquiry, several nonprofit groups said TVA needed a stronger decarbonization plan than its current 2050 goal.

Wagner is a 31-year veteran of TVA’s inspector general’s office, where he served as an investigator and auditor until his retirement in 2017. Before that, he worked in TVA’s nuclear power segment.

Wagner committed to performing program reevaluations of TVA’s audits and investigations to determine possible process improvements.

All nominees agreed to Markey’s ask to pay close attention to TVA’s coal ash dumps. Markey also asked that nominees pledge to place emphasis on energy efficiency measures.

The committee will vote on the nominations in the weeks ahead. A full Senate vote will follow.

The hearing comes as TVA risks losing the largest of its 153 power company customers, Memphis Light, Gas and Water (MLGW), over affordability concerns and low renewable energy investment. MLGW and a third-party contractor hired to oversee a request for proposals are currently evaluating 27 bids for alternative electricity supply, including one from MISO.

The city utility has previously said it will release a short list of finalists and invite the companies to prepare presentations this summer. After that, MLGW plans to request final offers and potentially award a contract in December.

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Forum: Collaboration Key in Minimizing Enviro Impact of NJ Offshore Tx

The key to minimizing the environmental impact of running transmission lines from New Jersey’s offshore wind projects to the onshore grid will be collaboration and coordination between developers to tie several projects to the same cable ashore, speakers told a state Board of Public Utilities (BPU) hearing Monday.

The suggestion emerged at the third of four hearings into the proposals submitted under FERC Order 1000’s State Agreement Approach (SAA), a solicitation process conducted by New Jersey with PJM in which 13 developers have offered 80 suggestions on how to upgrade the grid to handle the future wind-generated power.

The hearing focused on environmental and permitting issues that are expected to surface in the development of an enhanced transmission system, including the sensitive issue of how to secure public support for the projects and curb opposition. In New Jersey, some elements in the tourism and fishing sectors — and local residents near to where cables from the offshore wind turbines would come ashore — all oppose the projects.

Jeff Nield, an environmental consultant, told the hearing that a system that tied several projects to a single corridor of HVDC cables would be preferable to several projects each running their own line ashore and creating “multiple cable landfall locations.” Tying several projects to cables following the same route, and using a common substation location, would minimize the “overall environmental footprint,” reducing the sea floor disturbance and disruption of neighborhoods when the cable comes on land, he said.

Nield represents developer Mid-Atlantic Offshore Development (MAOD), which submitted three proposed cable routes. It is a joint venture between EDF Renewables North America and Shell New Energies US, who also partnered to submit the proposal for Atlantic Shores, one of New Jersey’s approved offshore wind projects.

A single-cable corridor, Nield said, would benefit from using HVDC technology, which is able to “transmit more electricity from offshore wind projects through fewer circuits occupying less area offshore and on land.” And a “coordinated transmission solution can also decrease the potential conflicts with other resource users,” he added, citing the example of the impact on shipping.

“This equates to fewer potential conflicts with shipping because cables are routed in one well sited corridor, and it minimizes the areas that conflicts can occur with commercial and recreational fishing,” he said.

That reduction in disruption also could make for a smoother passage for the transmission project through the environmental process, said Michael Sole, vice president of environmental services at NextEra Energy, which submitted several proposals for routes.

“The key thing is fewer environmental impacts means lower permitting risks,” said Sole, who displayed a presentation slide that showed a project with a single trunk line linking four wind areas and a project with several cables coming from the wind areas and only joining together in a single collector station closer to the shore.

The single-trunk line “minimizes the footprint and impact of cable routes coming in onshore as compared to an alternative solution where if every wind developer had to bring a landing into the shore,” he said. “So, the question of a coordinated transmission approach is: Can it be done efficiently with an offshore wind development? And the short answer is: absolutely.”

Fishermen Doubts

The forum followed two earlier hearings that focused on the proposals submitted and the BPU’s evaluation process, and how they would be integrated into the existing grid. The BPU expects to decide on the proposals in October.

New Jersey, with a mandate from Gov. Phil Murphy that it reach 100% clean energy by 2050, see its growing offshore wind sector as a key element in the effort and has set a goal of 7.5 GW from the sector. The state has so far approved three offshore wind projects — the 1,100-MW Ocean Wind and 1,148-MW Ocean Wind II, and the 1,510-MW Atlantic Shores — in two solicitations, with three more solicitations expected to be awarded by 2027 and in operation by 2033.

The first three projects included plans to bring the energy ashore. But the BPU, through the SAA process, is looking for a more efficient way to do that for future projects.

In presenting the problem to potential developers, the board sketched out three general proposals for the transmission elements that could be addressed, including the upgrades needed. The proposals also included an “offshore transmission backbone” that would run parallel to the coast and provide a connecting strip to receive the energy from the wind farms and pass it on to cables headed for the shore. (See Fierce Competition in Plans to Upgrade NJ Grid.)

The potential disruption of marine life and in the coastal communities through which any cable would pass through is among the most sensitive faced by the offshore wind projects. Ocean Wind is facing vigorous opposition in the tourist town of Ocean City in South Jersey, through which the cable would pass as it goes to a now closed coal-fired power plant in neighboring Upper Township. (See Ørsted NJ Wind Project Faces Local Opposition.)

Commercial fishermen, who are among the most vigorous opponents of the wind projects, fear that the projects will damage habitats, perhaps scaring fish away from long-time fishing areas, and that it will be dangerous to fish around the turbines. Fishing representatives say the combination of the weight of the fishing nets and the impact of the waves, wind and tides passing through rows of turbines can make it difficult and dangerous to maneuver a fishing vessel. (See Fishing Industry Concerned About NY Bight OSW Plan.)

Scot Mackey, a lobbyist for Garden State Seafood Association, a 1,200-member industry group that represents fishers of scallop, clam and other fish, commended the BPU and state Department of Environmental Protection (DEP) for “trying to play catch up with this issue.” But he added that the impact of the cable and transmission infrastructure should have been addressed before.

“We are greatly concerned about the impact of transmission,” he told the hearing. “We support minimizing the number of cables in the greatest possible way to minimize the impact on commercial fishing, most of which is done via bottom [and] midwater trawl pulling large structures through this environment.

“We are greatly concerned with the size, scope and cumulative effects of such huge projects in such a short period of time being proposed off our coast, in prime fishing grounds,” he said.

Zachary Klein, a policy attorney for Clean Ocean Action, also questioned the pace at which the offshore development is unfolding.

“Given the seriousness of the risks at play, it seems more responsible to start with a pilot-scale offshore wind development in the mid-Atlantic to minimize the impacts of bringing energy onshore while we figure out how to do so most responsibly, in greater volume,” he said.

“I just urge that the approach to minimizing these impacts not be looked at so rigidly,” he added. “And that if necessary or appropriate, we take a step back, and consider that maybe reducing or not jumping to rapid industrial development might help ensure that this interconnection with the grid can be done in the most responsible way possible.”

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FERC Accepts PJM CTOA Revisions

FERC on Tuesday accepted revisions to PJM’s Consolidated Transmission Owners Agreement (CTOA) changing the voting rules in the Transmission Owners Agreement-Administrative Committee (TOA-AC) and giving more voting power to larger transmission owners in the RTO (ER22-358).

PJM TOs in November filed the proposed revisions to the CTOA. The changes

  • called for the removal of an individual vote majority requirement “where an extreme supermajority of ownership supports an action;”
  • permitted voting action to occur “where a quorum of an extreme supermajority ownership is present;”
  • provided “comparable changes to the conduct of simple majority votes,” and;
  • limited the open meeting requirement to matters subject to a two-thirds voting rule under the existing CTOA language.

The commission said the revisions received “broad support” among transmission owners in a vote taken in October at the TOA-AC. The revisions become effective retroactively to Jan. 10.

“We find that the proposed CTOA revisions are just and reasonable as they are limited modifications to the CTOA that allow PJM Transmission Owners to resolve concerns potentially affecting their ability to achieve the needed vote to propose tariff changes to the Commission, and to effectively and efficiently conduct the business of the TOA-AC and execute their responsibilities as transmission owning members of PJM pursuant to the CTOA,” FERC said in its order.

Issues

The TOs said the CTOA currently features a voting structure based on a combination of two separate votes needed to act on an issue: an individual vote based on the votes of individual, unaffiliated PJM transmission owners; and a weighted vote based on the net asset value of each PJM transmission owner’s transmission facilities. According to the rules of the CTOA, no individual TO can have a weighted vote of more than 24.9% of the sum of the weighted votes.

Voting under current CTOA rules at the TOA-AC is divided into two procedures, including an action where a supermajority, or two-thirds, of the individual and weighted votes is required, or an action where a simple majority of both the individual and weighted votes is required.

The voting items requiring a supermajority include comments on the Regional Transmission Expansion Plan (RTEP) and tariff changes related to the recovery of transmission-related costs, including “joint rates or the PJM transmission rate design.” If a proposed issue such as a tariff change is supported by 95% of the weighted vote, a simple majority of the individual vote is required instead of the two-thirds rule.

The TOs said since the CTOA voting rules were adopted in 2006, there have been “several significant developments” impacting the number of transmission owners in PJM and the type of facilities qualifying a company to become a TO.

“PJM transmission owners assert that the commission’s approval of NERC’s definition of bulk electric system made it possible for small municipal electric systems to be eligible to have their transmission facilities integrated with the PJM region and become PJM transmission owners and thus parties to the CTOA,” FERC said in its order.

The TOs said without changes to the CTOA, the required majority individual vote “could create difficulty” in achieving consensus on tariff changes that “protect the PJM transmission owners’ substantial investment in the PJM transmission system that fairly allocate its costs among their transmission customers.” The TOs also said the CTOA should acknowledge the differing levels of investment among the voting entities, pointing out that more than $67 billion was invested in the PJM transmission system as of the beginning of 2021 with individual TO investments ranging from more than $140,000 to almost $15 billion.

In the proposal, the TOs requested the elimination of the majority individual vote approval “in a situation in which the requirement for a two-thirds vote is not met, but a weighted vote of 95% approves the proposal.” The proposal will leave the 95% weighted vote requirement in the CTOA unchanged.

The TOs also argued that the “proliferation of smaller, non-traditional transmission owners could also frustrate the ability to achieve quorum at TOA-AC meetings and thus the ability of the transmission owners to conduct business.” The proposed CTOA revisions called for a quorum to be present when “either 50% of the PJM transmission owners eligible to vote are in attendance or when PJM transmission owners representing 95% of the weighted vote are in attendance.”

In making its argument regarding voting in ISOs/RTOs, the PJM TOs cited FERC’s decision in 2019 to reject RTO Insider’s bid to force the New England Power Pool to open its meetings to the public and press, saying it lacked authority to act. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

“The commission found that rules prohibiting press and public access to NEPOOL meetings do not directly affect rates, because they do not affect who may vote on NEPOOL proposals,’” the TOs said in their filing.

Protests

A joint protest was filed in November by AMP Transmission, Old Dominion Electric Cooperative and Silver Run Electric, arguing that the impact of the CTOL changes would “disenfranchise non-traditional transmission owners whenever enough of the large incumbent PJM transmission owners coordinate their votes, as they have done in the past.”

The protesters said the changes would allow a “supermajority” of weighted votes to “override a proposal’s failure to obtain the required share of individual votes” and to “negate” the individual votes of the minority PJM TOs. They also argued that the TOs “fail to identify a single instance” where they were stopped from making a filing under the existing CTOA rules by the non-traditional transmission owners.

“Protesting parties assert that the proposed CTOA changes are unjust and unreasonable because they are premised entirely on speculation that ‘the proliferation of smaller, non-traditional [PJM] transmission owners’ could prevent a filing by larger incumbent PJM transmission owners,” the commission said in its order. “Protesting Parties contend that they have no incentive to block a filing that does not adversely affect their interests and that the existing TOA-AC voting rules already provide sufficient protection to incumbent PJM transmission owners.”

The commission said it disagreed with the argument that the CTOA revisions will disenfranchise the non-traditional PJM transmission owners.

“All PJM transmission owners retain the opportunity to express their views on proposals and to cast a vote,” the commission said in its order. “Furthermore, we find that the proposed revisions rebalance the CTOA voting rules to better align with individual PJM transmission owners’ economic stakes in the transmission system.”

Consenting Commissioners

FERC commissioners Allison Clements and Willie Phillips issued a concurring opinion, saying the revisions were approved by 80% of the individual vote under the current voting rules at the TOA-AC. They said PJM stakeholders also retain the ability to protest Section 205 filings “regardless of size.”

The two commissioners said they had “some concerns” with the voting changes, but they were not great enough to reject the proposal. They specifically pointed to the removal of the individual vote, saying the changes make that vote “irrelevant” when the TOs achieve a 95% or greater weighted vote.

The commissioners said they were also “concerned” that the TOs “failed to adequately respond” to a question in a deficiency letter issued by FERC about whether it was just and reasonable “for a small number of PJM transmission owners with the largest transmission rate base to meet the 95% weighted vote threshold for approving a voting item when a majority of individual PJM transmission owners vote against the item.”

“Instead, the PJM transmission owners dodged the question by revising it,” the commissioners said in the concurrence.

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ERO Backs FERC’s Cyber Monitoring Proposal

FERC’s proposal to add internal network security monitoring (INSM) to NERC’s Critical Infrastructure Protection (CIP) reliability standards is an “appropriate approach to address” the growing risk of cyber penetration into secure electronic networks, NERC and the regional entities said last week.

The ERO Enterprise asked to take the lead in the process to implement the commission’s plan (RM22-3).

However, in their comments on FERC’s proposal, NERC and the REs — along with other stakeholders — also warned FERC not to act too quickly on forcing through changes to the CIP standards. One of the commission’s suggestions — to impose INSM on low-impact bulk electric system cyber systems (BCS) — proved especially unpopular, with some respondents urging FERC to drop the idea altogether.

FERC suggested modifying the CIP standards in January, issuing a Notice of Proposed Rulemaking that would add INSM — defined as a set of practices or tools for network visibility including anti-malware, intrusion detection and prevention systems, and firewalls — for high- and medium-impact BCS. (See FERC Proposes New Cybersecurity Standard.) In its order, the commission also called for comments on whether low-impact BCS should be included in the standards effort as well.

The NOPR was prompted by recent cyberattacks in which hackers gained access to the internal networks of target organizations. In particular, commission staff cited the SolarWinds hack of 2020, in which attackers — later identified by the U.S. as officers of Russia’s Foreign Intelligence Service — penetrated the official update channel of SolarWinds’ Orion network management software and distributed malicious code to thousands of public and private sector organizations worldwide.

Staff said the SolarWinds attackers “bypassed all network perimeter-based security controls traditionally used to identify the early phase of an attack” and left the company no way to detect their activities inside the network. They warned that because the CIP standards currently only require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around the internal network to which BCS are connected — to the outside, utilities that do not implement INSM are vulnerable to similar tactics.

Fears About Size, Complexity of Task

In its response, the ERO Enterprise emphasized that it “appreciates the risks identified in the NOPR” and agreed with the idea of incorporating INSM requirements into the CIP standards. Promoting awareness of “components or activities on [utilities’] systems” has been a major focus of the ERO for some time, the comments said, referring to NERC’s previous work with FERC staff on supply chain vendor identification. (See FERC, NERC Offer Cyber Supply Chain Guidance.)

NERC and the REs were not alone in their support, both for the principle that utilities should have insight into their networks and for how the commission hoped to achieve the goal. The ISO/RTO Council (IRC) called INSM “a necessary and valuable security practice,” while the Bonneville Power Administration (BPA) said it “supports the commission in recognizing INSM as an important cybersecurity protection that entities should begin deploying.”

But not all respondents were wholehearted in their approval of the proposal. A group of trade associations, including the Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association, and the Electric Power Supply Association, said that “INSM holds significant potential” to promote electric reliability, but that the technology faces “significant obstacles” in the near term, mainly that there are currently few subject matter experts “capable of working with the technology,” while the technology itself is also not widely available.

Many commenters were similarly concerned about pushing utilities into investing in technologies or practices that are not yet fully mature. The North American Generator Forum (NAGF) pointed out that “all high and medium BCS are not the same” and said that a network monitoring approach may work on one system but not another. In addition, NAGF warned that encrypted network traffic would be impossible to monitor unless it is all routed through a central location with universal encryption keys. Such a location would inevitably become a “high value target for attackers,” its comment said.

Respondents resisted even more strongly the idea of requiring INSM at low-impact BCS: Idaho Power noted that such systems, “by their very definition,” pose little risk to the BES, and as a result the benefit of implementing network monitoring is likewise small. Similarly, the utility said systems without external routable connectivity (ERC) — whether low- or medium-impact — cannot have INSM installed without also adding ERC. Imposing INSM on these systems may not be worth the cost, particularly since systems without ERC pose far lesser risks for hacking.

This sentiment won many supporters. Even the ERO Enterprise, while supporting “considering” INSM on low-impact systems, said that adding this requirement to the CIP standards would require “extensive revisions” because the standards don’t currently define low-impact BCS. BPA went further, arguing that any mandate for internal network monitoring should apply only to high-impact systems, at least initially, with application to medium-impact systems — only those with ERC, for reasons similar to Idaho Power’s — coming later.

All respondents urged FERC not to move too quickly in forcing INSM on utilities, considering the cutting-edge nature of the technology. NERC and the REs suggested that the commission “defer to NERC regarding the timeline for any standards development” due to the “complex considerations” faced by the ERO and industry stakeholders.

“While the ERO Enterprise intends to act expeditiously to support any directed standards revisions, [it] respectfully requests the Commission not impose deadlines that could hamper thoughtful deliberations on technical considerations, scalability and manageability for responsible entities of all sizes, and whether any further implementation requirements may be necessary,” the ERO said.

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Ohio Lawmaker’s Pro-EV Manufacturing Bill Worries Colleagues

The first legislative hearing on an Ohio bill designed to jumpstart the production of electric vehicles and EV components in the state drew cautious questions from some members of the Senate’s Energy and Public Utilities Committee on Tuesday.

Sponsored by Sen. Michael Rulli (R) — who represents the greater Youngstown area, a former steel manufacturing center — the bill would provide job training funding and incentives for companies building production facilities in the state.

S.B. 307 would also provide state sales tax exemptions of $2,000 to those who lease or buy EVs, $1,000 for people or companies buying or leasing used EVs, and $1,000 for those buying or leasing new plug-in hybrids.

The sales tax exemptions alone could cost the state between $55 million and $70 million annually, according to the Ohio Legislative Service Commission’s analysis. Most of that money would have gone into the state’s general fund.

The bill would appropriate $15 million in general revenue funds in 2022 and 2023 fiscal years for manufacturing retooling and new equipment. It would provide $10 million for retraining during those initial fiscal years.

The legislation would also create a new charge on business and consumer electric bills, subject to approval by the Public Utilities Commission — to allow distribution utilities to recover the cost of new “transportation electrification programs.”

In initial remarks when he introduced the bill a week ago, Rulli said the stakes were too high for Ohio to ignore the transformation of the auto industry because the switch to electric systems would eliminate many of the state’s 108,000 auto and auto parts jobs.

“The auto industry is going through a global transition,” he said. “Manufacturers have pledged to invest $330 billion on electric vehicles production by 2025. This means they are making decisions right now about where to build new factories and which of the existing factories will transfer to EV production. Companies are making decisions about where the next generation of auto manufacturing jobs will be. I want that to be right here in the Buckeye State.”

At Tuesday’s hearing, Sen. Jerry Cirino (R) asked whether the state would need more “baseload capacity” by 2035, a year when General Motors has announced it will build only EVs. “I’m just concerned about the ability to provide the baseload power to charge all of these vehicles, whether they’re fast- or slow-charging batteries,” he said in a question to John Walsh, CEO of Endera, an EV manufacturer that last year opened a manufacturing plant for commercial EVs in western Ohio.

“We design our charging infrastructure deployments to charge in times when no one needs power, so we charge at night,” Walsh responded. “That’s one element. The second element is that we have what’s called battery energy storage stations. So, there are batteries actually coupled with the charging stations themselves, that consume power when there’s excess power, and they charge the vehicles when there’s a high demand for power.”

Sen. Andrew Brenner (R), owner of a plug-in hybrid, said he has noticed his electric bill has gone up slightly since purchasing the vehicle and wondered what the impact would be when more Ohioans have plug-ins over the coming decade.

“We have 4,650,000 cars sold annually in the state. … Less than 2% of all cars are electric, which would make about 93,000 cars in the state [that are] electric of some sort,” he said. “I realize this bill is trying to build up capacity for competition for a market. I’m just not sure I’m convinced given the fact that there are very few electric charging stations. Just to scale this up would seem to be a herculean task. What happens if you go from, say, 93,000 cars getting charged to 465,000 cars, which is 10%, or 20% at 930,000 cars per day getting charged?

“These are economies of scale that I’m not really sure we can get to with the current setup and the way the batteries are and the way the charging is for literally everything that needs to happen, let alone the infrastructure needed to build all those cars,” he said.

A current electrification rider on the bills of customers of the state’s AEP Ohio (NASDAQ:AEP) customers is costing residential customers 12 cents/month and business customers 62 cents/month. That rider pays for 375 network-connected smart EV charging stations.

Philip Dion, AEP chief customer officer, spoke in favor of the bill, saying that production of EVs in Ohio would not likely lead to an insurmountable increase in demand because most EVs would be purchased on the west and east coasts before Ohioans would buy them.

But lawmakers wanted to know just when demand would surge in Ohio.

“I think what you will see is that there will be a need on the distribution system, to enable us to balance the system,” he said, adding that the company could offer time-of-use rates and technology to allow it to control when EV charging could occur in order to avoid an immediate buildout of its distribution system.

“But make no mistake, I’m not avoiding your question,” Dion said. “We’re going to use more electricity. We’re going to need more infrastructure to meet that. The balancing, though, is our job, especially as the operators of the grid are sort of the traffic cop. It’s our job to work with the government.”

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Mass. AGO: Pipeline Leak Program Review Missing in ‘Future of Gas’ Case

The Massachusetts Attorney General’s Office is looking for a way to ensure that the state’s natural gas leak mitigation program aligns with the state’s net-zero by 2050 target set in law last year.

“Utilities are continuing to spend millions of dollars annually on new infrastructure that we may not need in the future, so we need to rethink how we reduce methane and gas leaks in the gas distribution system,” Rebecca Tepper, chief of the AGO’s Energy and Environment Bureau, told legislators Monday during a Future of Gas oversight hearing of the Senate Global Warming and Climate Change Committee (GWCC).

In February, the AGO joined the Department of Energy Resources in asking the Department of Public Utilities to establish a working group to study utilities’ Gas System Enhancement Plans (GSEPs) in the next phase of the department’s ongoing Future of Gas docket (20-80). However, the department declined to convene the group.

“Addressing GSEP is a critical path to our decarbonized future,” Tepper told lawmakers. The legislature, she said, can require the DPU to establish a GSEP working group.

As part of DPU’s gas case, the state’s utilities filed proposals in March for reducing gas system emissions based on recommendations in an independent consultant’s report on potential state decarbonization pathways. (See National Grid Proposes 100% Fossil-free Gas System in Mass.) The report’s assumptions, Tepper said, rely on the continuation of GSEP and the costs associated with it.

A 2014 law allows the state’s utilities to file annual GSEPs with regulators for how they will repair or replace aging pipelines to address leaks and recover costs for those plans. The estimated cost for the utilities’ pipeline work, based on the pathways report, would be $40 billion through 2039, Dorie Seavey, an independent economist, said during the hearing.

Pathways in the consultant’s report would not be feasible if GSEPs “disappeared,” Seavey said. “The scenarios assume an upgraded gas distribution network outfitted with polyethylene plastic pipe ready to deliver fracked gas blended with biofuels, synthetic natural gas or hydrogen.”

Seavey sees GSEP’s purpose changing.

“The program’s founding mission was to reduce leaks, promote safety and lower methane emissions,” she said. “It has become the gas companies’ accelerated investment vehicle for making our gas distribution system biofuel and hydrogen ready.”

If the DPU approves the gas utilities’ proposals in the Future of Gas docket, it would establish a ratepayer tariff for the new fuels that is additional to the existing GSEP tariff, she said.

GWCC Committee Chair Sen. Cynthia Creem believes the department’s gas case will not be “complete or fair” if it does not consider the implications of GSEP for the state’s net-zero goal. And she is “seriously concerned” about the safety, cost and viability of using hydrogen and biofuels in decarbonizing the gas system.

“Most importantly, I have concerns about whether [hydrogen and biofuels] represent a path to net zero or merely offer a net-zero mirage,” she said.

Fair Participation

Stakeholders of the Future of Gas docket have asked the DPU to reconsider how it will continue with the gas proceeding now that the utilities have submitted their emission reduction proposals.

In a March 24 memorandum, the DPU established a schedule that five organizations, including Sierra Club and the Environmental Defense Fund, say does not provide ample opportunity for stakeholder input on the utilities’ proposals. The schedule puts the focus of the DPU’s case on reviewing the assumptions of the consultant’s report and the utilities’ proposals, and creation of a regulatory and policy roadmap for the state’s gas distribution industry.

“Failure to allow for the presentation of technical evidence and for cross-examination of the utilities’ consultants will result in a regrettably flawed outcome from this proceeding,” the petitioners said in a March 28 motion for consideration.

They are asking the DPU to “extend” the schedule to allow entities to obtain party status in the docket, participate in discovery, present testimony and cross-examine witnesses. The petitioners said that, despite their engagement with the utilities’ consultants to date, their feedback was ignored, making the utilities’ proposals “inherently flawed.”

The state’s five gas utilities asked regulators to deny the motion in an April 4 response to the petition, saying it would constrain the department’s ability to include a broad spectrum of stakeholders, regardless of their ability to retain legal counsel.

“The legislature may have to intervene … to ensure that there is an opportunity to scrutinize the gas company’s proposals before the Commonwealth chooses which future to pursue,” Creem said in the GWCC committee hearing.

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Praise for ERCOT Operators’ Performance in February 2021

FERC staffers praised ERCOT operators Tuesday for preventing a worse catastrophe during last year’s devastating winter storm.

Reacting to criticism of ERCOT during the immediate aftermath of the storm’s extended outages and financial and human damage, Heather Polzin, legal counsel and reliability coordinator for FERC’s Office of Enforcement, called out the actions within the grid operator’s control center that prevented a total collapse of the system when the grid’s thermal generation failed to show up.

“The actual ERCOT operators that were on duty that day did a tremendous job in keeping the grid operational in the face of this challenge,” she said during a presentation before the Texas Reliability Entity.

Polzin was joined by the commission’s David Huff and NERC’s Kiel Lyons as they reviewed their joint report on the February 2021 storm, published in November, during a Talk with Texas RE webinar. The report detailed how the severe cold affected bulk electric system reliability, leading to widespread generation outages, derates or failures to start and forcing more than 23 GW of manual firm load shed. (See FERC, NERC Release Final Texas Storm Report.)

Huff, an electrical engineer, said a team that included regional entities’ staff “deeply” investigated the event, which also led to load sheds in MISO and SPP. He said each of the grid operators had only nine minutes to prevent an additional 17 GW of generation units from tripping offline and leading to blackout conditions.

“In all three footprints, the operators coordinated through these extreme emergency conditions,” Huff said. “The ERCOT operators, from our view, took the steps necessary to keep the balance of generation and load to avoid further emergency conditions or possible blackout conditions. The team really thought that the operators took the appropriate measures and maintained reliability.”

As others have said since early last year, Huff said ERCOT’s lack of sizeable interconnections with the rest of the nation’s grid hampered its ability to import power from the east to meet demand, while MISO and SPP were able to import more than 13 GW of power from the rest of the Eastern Interconnection.

“ERCOT … thus needed to shed the greatest amount of firm load to balance electricity demand with the generation units that were able to remain online,” Huff said.

The storm led to unprecedented generation shortfalls, according to the report, with 1,045 individual units experiencing 4,124 outages, derates or failures to start. Gas-fired generators accounted for most of the units knocked offline with 604, or 58% of all units.

The report team found that fuel issues were to blame for 31% of the outages, derates or failures to start, with 87% of the fuel supply problems related to the natural gas supply. The storm caused the largest monthly decline of natural gas production on record; between Feb. 8 and 17, total natural gas production fell by 28% in the Lower 48 and 70% in Texas (as compared to January average).

Polzin said recurring problems between gas and electric interactions have become common during recent cold-weather events.

“You see demand for natural gas from the natural gas-fired generators increasing dramatically during a cold weather event like this,” she said. “At the same time, you may see demand from local distribution companies for local heating supply increasing dramatically, while at the same time, you may see gas supply drop off because of the weather.”

The report makes a number of recommendations to increase coordination between the electric and gas industries. It recommends legislators and regulators with jurisdiction over natural gas infrastructure require the gas infrastructure facilities to have cold-weather preparedness plans, including measures to prepare to operate during a weather emergency. The report also suggests gas entities undertake voluntary measures to prepare for cold weather.

The report team has proposed a forum where those lawmakers and regulators would work with FERC, NERC and the REs to gather input from the grid operators and gas entities identifying concrete actions to improve the gas infrastructure’s reliability and support BES reliability.

FERC is hosting a technical conference April 27-28 on winter readiness measures.