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November 9, 2024

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Bonneville Commits to Joining Western EIM

The Western Energy Imbalance Market is poised to make its largest expansion ever next spring after the Bonneville Power Administration said Monday that it will join the market in March.

With 15,000 miles of high-voltage transmission and 31 hydroelectric projects under its control, BPA will be the largest transmission- and hydro-provider in a market that currently includes 14 members with territories spanning much of the Western Interconnection.

“This decision aligns with Bonneville’s strategic plan and opens up an opportunity to increase revenues through additional sales of surplus power and to reduce costs through greater efficiencies,” BPA Administrator John Hairston said in a statement. “As the West moves rapidly to decarbonize the grid, Western EIM participation will help us navigate future challenges and leverage opportunities to benefit our customers and the Northwest.”

BPA’s decision comes three years after the federal power marketing agency began exploring membership in the CAISO-operated WEIM and two years after it signed a nonbinding implementation agreement to begin integrating the ISO’s systems into its operations. (See Bonneville Power Signs Agreement with EIM.)   The agency said Monday that its internal preparations are “on track” and that it has already begun testing with the ISO.

“Bonneville and its public power customers are highly valued partners for the ISO, and we look forward to further strengthening our working relationships,” CAISO Chief Operating Officer Mark Rothleder said.

BPA’s decision, though not a surprise, marks CAISO’s second victory this month in its competition with SPP, which earlier this year launched the Western Energy Imbalance Service (WEIS). A competing real-time market that has already attracted members in the Rocky Mountain region, the WEIS could provide a foothold for a full RTO in the West. In June, Xcel Energy postponed its effort to join the WEIM in order to consider its alternatives with SPP. (See Xcel Delays Joining EIM to Weigh Options.)

But two weeks ago, the Western Area Power Administration’s Desert Southwest Region signed its own implementation agreement with the WEIM, putting the agency on track to join in 2023. (See WAPA Desert Southwest Region to Join Western EIM.) By that time, the WEIM will consist of 22 members representing 84% of the West’s load, CAISO estimates.  

The ISO has taken key steps to seal the deal for BPA’s membership, including revising its tariff to create a new category of default energy bid — a “hydro DEB” — that estimates the opportunity costs for hydro in the WEIM to avoid forcing those resources to make unprofitable trades under certain conditions. (See CAISO Goes 2 for 3 on EIM Hydro Rule Changes.) 

And last month, CAISO’s Board of Governors and the WEIM’s Governing Body both unanimously approved a plan that would delegate more authority to the Governing Body over issues affecting the WEIM, a move widely popular among Northwest utilities and power producers. (See CAISO Agrees to Share More Power with EIM.)

Hairston said Monday that BPA’s WEIM membership could be a steppingstone to other forays into regional markets.

“Western EIM participation is a great introduction to emerging markets in the West. We hope to build on this experience to assess future market-based opportunities,” he said.

BPA is already heading in that direction, having last month proposed to participate in the next non-binding phase of Northwest Power Pool’s Western Resource Adequacy Program (WRAP). Interest in the WRAP has expanded to include utilities currently outside the NWPP’s current coverage area. (See RA Program will Require Restructuring of NWPP.)

And BPA signaled that it would also consider developments taking shape farther east.

“In addition to participating in the Western Resource Adequacy Program, BPA is closely monitoring the potential formation of day-ahead markets in the West,” the agency said. “Both the California ISO and Southwest Power Pool have presented initial concepts that could provide additional opportunities and benefits for BPA and its customers.”

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Conn. Regulator Nudges ISO-NE to Share Tx Data to Support OSW

States in New England are relying on offshore wind (OSW) to cut greenhouse gas emissions, but they need to hear from ISO-NE on where transmission upgrades are most needed before they can start harnessing the energy.

“I think [ISO-NE] is best-positioned to be able to provide the states with that kind of planning analysis,” Connecticut Department of Energy and Environmental Protection (DEEP) Commissioner Katie Dykes said at the Environmental Business Council of New England’s Connecticut Offshore Wind Webinar on Friday.

Other onshore renewable energy resources, Dykes said, need to be considered in the transmission planning process for OSW to avoid unintended consequences of congestion or curtailment between resources.

“The [ISO-NE] planning process for transmission has been pretty reactive,” Dykes said, and states are calling for a more proactive approach to building out the grid.

But New England states also need to work with ISO-NE in providing information on what their transmission and climate goals are so the system operator can include them in its planning efforts.

Since 2012, for example, Connecticut’s Integrated Resource Plan (IRP) has assessed supply and demand to formulate recommendations for the state’s electricity needs. The final version of the latest IRP is due later this month, Dykes said. And in Massachusetts, Gov. Charlie Baker’s administration developed a Decarbonization Roadmap to model how the state will reduce emissions at least 85% by 2050, including plans for electrification that require significant transmission updates.

Connecticut and Massachusetts want to plug the IRP and roadmap into ISO-NE’s scenario planning process, Dykes said.

Last year, all six New England states, through their representatives to the New England States Committee on Electricity, signed a vision statement that calls for ISO-NE to make the changes necessary to cost-effectively build the transmission needed to integrate OSW and other renewables.

In July, FERC opened a rulemaking to reconsider its rules on transmission planning, cost allocation and generator interconnection, acknowledging that Order 1000 has failed to provide interregional expansions to deliver increased renewables and meet the challenge of climate change. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

FERC’s review is important, Dykes said, because New England is “long delayed in reforms to the transmission procurement process.”

To unlock the transmission investment needed to integrate future offshore wind and other renewables, it is “critical that we’ll be able to participate in the process,” Dykes said.

Connecticut currently has about 90% of its electricity load under contract with renewable and zero-carbon resources, including the 704-MW Revolution Wind project between Eversource Energy (NYSE: ES) and Ørsted off the coast of both Connecticut and Rhode Island. The developers expect to place the project in commercial operation by 2025.

In addition, Vineyard Wind’s 804-MW Park City Wind project is located 23 miles off the coast of Massachusetts but will bring renewable energy to the residents of Connecticut.

Prices for OSW are steadily declining, Dykes said. The contract prices for Connecticut’s projects declined 20% from $99.50/MWh to $79.83/MWh, she said.

“These [prices] are a testament to the success of the competitive procurement mechanism Connecticut has been using to invest in OSW, as we provide certainty and finance stability for these projects going forward,” Dykes said. “The next challenge we have to tackle is transmission.”

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DOE Targets 90% Cut in Cost of Long-duration Storage

To decarbonize the fast-evolving U.S. grid by 2035, long-duration storage technologies that can provide 10 or more hours of power will have to be developed and deployed by 2030, according to Eric Hsieh, director of grid systems and components at the U.S. Department of Energy.

But hitting that deadline may not be possible because of the long and expensive process new technologies must go through to test and validate their performance, he said.

To allow enough time for manufacturing, permitting, interconnection and construction, “any new technologies would probably need to be ready by 2030” to be operational by 2035, Hsieh said during the DOE’s Long-Duration Storage Shot Summit on Thursday. “So, under any scenario of achieving this goal, there’s less time on the calendar, between now and deployment, than the time these technologies” would normally need for performance testing.

This “information gap” — and the use of artificial intelligence and machine learning to accelerate testing — is now the focus of a consortium of researchers at the DOE’s national laboratories. They have launched a Rapid Operational Validation Initiative (ROVI) to build the tools and datasets that could cut the performance testing process from years to weeks, said Eric Dufek, department manager for energy storage at the Idaho National Laboratory.

The national labs have already developed some AI and machine learning capabilities that might soon “do rapid, accurate and cost-effective performance characterization and provide the quantitative, reliable certainty to everybody that is developing and deploying different assets,” Dufek said during a panel on the initiative.

The need for speed is at the heart of the Long-Duration Storage Shot (LDSS), the second of the DOE’s Earthshots aimed at driving down the costs of certain key energy technologies that will need to be commercialized and deployed at scale to reach President Biden’s 2035 deadline for a 100% clean electric grid. Six to eight “shots” are planned for the initiative, beginning with the Hydrogen Shot, announced in June, which is aimed at cutting the cost of green hydrogen, produced with clean energy, from its current price of $5/kg to $1/kg within a decade.

Launched in July, the LDSS has set an even more ambitious target: cutting the levelized cost of long-duration storage 90% to 5 cents per kWh-cycle for 10 hours of duration or longer, Hsieh said.

That target is based on the 2020 capital costs and levelized cost of storage (LCOS) of lithium-based batteries, Hsieh said. At the same time, “the Storage Shot is technology-neutral and includes all technologies with a pathway to the specified cost and performance targets,” he said.

A wide spectrum of technologies is in the running to fill the long-duration space. Traditional pumped hydro currently accounts for more than 90% of grid-scale storage in the U.S., but other possibilities include liquid air, compressed air, hydrogen, flow batteries and gravity-driven technologies. For example, the California-Swiss startup Energy Vault uses tall towers to store and discharge energy by lifting and lowering 35-ton blocks of concrete.

The sheer number of “potential pathways here offer potential breakthrough avenues and obviously also challenges,” said Jason Burwen, interim CEO of the Energy Storage Association, who believes the DOE’s target is achievable.

“Each technology points you toward different cost problems to tackle,” Burwen said in a phone interview with RTO Insider. “Thermal storage technologies, for example, there’s a lot of promise there because you’re talking about materials and thermal mass, which can scale … probably fairly well at low cost, and then it becomes a matter of solving for the containment vessel associated with those.”

Speaking to RTO Insider on Monday, Yiyi Zhou, clean energy specialist at BloombergNEF, also saw a number of possible candidates for hitting the 5-cent target, including hydrogen, compressed air and aqueous, or liquid air, technologies.

“[The] levelized cost of hydrogen for renewable electricity has the potential to reach below U.S. $1,” Zhou said. “This is the equivalent to about 2.5 cents per kWh.”

But, she cautioned, an LCOS that low might only be applicable in certain markets.

Faster, More Granular, More Complex

Lithium-ion batteries are the dominant technology in residential and grid-scale storage today, allowing for durations of four to six hours and a range of flexible grid support services. But according to a range of policy makers and industry stakeholders at the LDSS summit, increasing levels of renewable energy on the grid will require longer-duration technologies.

“Once you get past 20 to 30% penetration of renewables, the whole system changes. It becomes faster; it becomes much more granular in terms of the information you require. It becomes certainly much more complex,” said Audrey Zibelman, who at the end of 2020 left her position as managing director and CEO of the Australian Energy Market Operator to join X, Google’s Moonshot Factory, as vice president for the electric grid.

“But [what] all that gets down to is that you need a huge amount of flexibility in the system; you need to be able to respond instantaneously to changes,” Zibelman said. “And you need to recognize that as weather [solar and wind] becomes some of your biggest fuels, storage becomes an increasingly critical feature both in managing the grid so that it can take advantage of the free fuel of weather and become much more efficient, as well as resilient, as well as reliable.”

Renewables and electrification of transportation, buildings and other sectors of the economy could result in some states seeing their electric grids shift from summer-peaking to winter-peaking systems, as is already beginning to happen in North Carolina, said Christopher Ayers, executive director of public staff at the North Carolina Utilities Commission.

With the state’s strong solar market pumping out excess power, “we need that energy that is produced in the afternoon in large quantities; we need it at 6, 7 and 8 in the morning on January, February and March mornings,” Ayers said. “Right now, we don’t have the technology that allows us to bridge that gap. Once we have long-duration storage and start integrating [that power] into the system, we can become more cost-effective by also leveraging low-cost energy generation.”

In the remote town of Cordova, Alaska, Clay Koplin, CEO of the Cordova Electric Cooperative, sees long-duration storage as “the holy grail.” Working with the DOE, the town of about 2,200 has been able “to modernize our grid and be very efficient with the resources we have, but [that] just can’t replace the need for storage,” Koplin said.

Long-duration storage would mean the town would be able to store excess solar energy from its long summer days to use during the winter, and eventually run 100% on clean power, Koplin said.

Data: A Two-fold Problem

Beyond cost-cutting, a major challenge for scaling long-duration technologies is validating their performance, a process that often requires a huge amount of data collected over years, said Ben Kaun, program manager for energy storage and distributed generation at the Electric Power Research Institute.

“Utilities are used to very long-life assets,” Kaun said during the panel on ROVI. “Battery energy storage technologies that are available right now typically are guaranteed for 10 to 20 years. That already raises some eyebrows for the stakeholder group. In addition, there’s only been a few years that most of these technologies have in-the-ground experience that we haven’t had the chance to prove out.”

And, with the grid constantly evolving, Kaun said, “This creates a situation where there’s insufficient predictive data about what’s going to happen to these assets in the future.”

Craig Horne, managing director of energy storage at natural gas and solar developer Wellhead Electric Company, agreed. “You really have a two-fold problem where you have a limited amount of data that predicts performance and then a limited amount of insight as to how that performance needs to manifest in order to bring in revenues and provide service to the customers,” he said.

A platform like ROVI would allow developers to “see that no matter how a use case may evolve, that we can get a high degree of confidence that this storage asset would be able to respond appropriately,” Horne said.

Getting the system up and running, however, will mean collecting and sharing performance data — including proprietary information — from a range of industry players, a problem the labs are already working on, Dufek said.

“If something is proprietary and not necessarily something you want the entire world to see, we can also deal with that,” he said. “We can clearly link and coordinate between those two sets so that we continue to evolve the entire system without actually developing or creating the need to develop a specific tool for every single activity.”

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PennEast Pipeline Throws in the Towel

Developers of the proposed PennEast Pipeline said Monday they are canceling the natural gas project, conceding defeat in a seven-year battle despite a U.S. Supreme Court ruling supporting their ability to seize properties in New Jersey via eminent domain.

“Although PennEast received a certificate of public convenience and necessity (CPCN) from FERC to construct the proposed pipeline and obtained some required permits, PennEast has not received certain permits, including a water quality certification and other wetlands permits under Section 401 of the Clean Water Act for the New Jersey portion of the Project,” the company said in a statement. “Therefore, the PennEast partners, following extensive evaluation and discussion, recently determined further development of the project no longer is supported. Accordingly, PennEast has ceased all further development of the project.”

The $1.2 billion 120-mile pipeline would have delivered shale gas from Luzerne County in Northeastern Pennsylvania to Transco’s pipeline interconnection in Mercer County, N.J.

Monday’s announcement was foreshadowed when four of the five partners — New Jersey Resources Corp. (NYSE:NJR), South Jersey Industries (NYSE:SJI), Southern Co. (NYSE:SO), and a subsidiary of UGI Corp. (NYSE:UGI) — told investors recently they were writing off about $354 million from their books, representing nearly their entire investment in the project. Enbridge Inc. also was a partner (NYSE:ENB).

Last week, the New Jersey attorney general announced in a federal court filing that PennEast had dropped its bid to condemn 42 parcels in which the state claims a property interest, most of them privately owned land on which the state Jersey has granted conservation easements.

In June, the Supreme Court ruled 5-4 that the Natural Gas Act allows private energy companies to seize “necessary”  land for a project if they have obtained a CPCN from FERC. New Jersey officials responded to the order with a vow to continue their fight against the project.

“I welcome today’s decision by PennEast to cease development on the PennEast Pipeline and am committed to protecting our state’s natural resources and building a clean energy future that works for all New Jerseyans,” Gov. Phil Murphy said in a tweet.

Abigail M. Jones, vice president of legal and policy at PennFuture, said the pipeline would have damaged streams, wetlands and forest habitat while increasing greenhouse gas emissions.

“New Jersey had denied critical environmental permits for the pipeline, which resulted in PennEast proposing to bifurcate its process and build the Pennsylvania-portion in phases to allow for construction to move forward,” she said in a statement. “PennEast’s announcement that they will cease development of the pipeline is great news, especially for the many landowners in Pennsylvania whose properties were threatened by eminent domain and clearcutting for a pipeline to nowhere.”

The Consumer Energy Alliance (CEA), a group backed by oil and gas producers and mining interests, said the cancellation was “a sign that even with a Supreme Court victory under its belt, critical infrastructure in the U.S. faces needless and politically-motivated opposition.”

“Unfortunately, a regulatory process designed to get things built safely and in the public interest has fallen prey to anti-business interests and compliant elected leaders,” said CEA Mid-Atlantic Director Mike Butler.

The Energy Information Administration reported last week that the U.S. benchmark natural gas spot price at the Henry Hub in Louisiana has been at a premium to Northeast natural gas hubs since the third quarter of 2020, “as total Appalachian supply exceeded demand growth and storage levels were above average.

“Although storage levels fell in 2021, other factors, such as record high Gulf Coast LNG exports, winter freeze-offs in Texas and neighboring producing areas, and Appalachian pipeline outages kept the Henry Hub price premium over Northeast hubs higher than 2018-2020 annual averages in 2021,” EIA said.

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UN Hosts Energy Dialogue During General Assembly

Nisha Pillai, BBC | United NationsAs world leaders gathered in New York last week for the United Nations General Assembly, presidents and prime ministers mixed with program directors and policy advocates at a conference to shape a unified global response to climate change through renewable energy.

“The conference is a way of bringing together [the 17 U.N. Sustainable Development Goals] on climate action onto the same trajectory,” said BBC World News presenter Nisha Pillai, who moderated a panel on “raising collective ambition.”

“Governments alone cannot do the transformations that are needed to fulfill this and also to get us to the goals of the Paris Agreement by the end of the century,” Pillai
said.Damilola Ogunbiyi, Sustainable Energy for All | United Nations

U.N. Secretary-General António Guterres on Friday convened a “high-level dialogue on energy” concurrent with the General Assembly in order to accelerate action on clean, affordable energy for all, the first gathering of leaders at the U.N. in more than 40 years devoted solely to energy issues.

Emerging economies need to feel like they’re part of the global struggle against climate change, said Damilola Ogunbiyi, special representative of the U.N. Secretary-General for Sustainable Energy for All.

“I always tell people from my own country, Nigeria, that energy is our climate action,” Ogunbiyi said. “Getting rid of 25 million generating sets is part of our climate action, as is giving 90 million people energy access. … But from tomorrow it’s all about how do we translate that ambition on the ground and how do we get a lot more people to deliver it.”

Co-investment Stimulus 


Achim Steiner, UNDP | United Nations
To consider how much the situation has changed in recent years, look at the stimulus packages that have been mobilized in the industrialized world, said Achim Steiner, U.N. Development Program administrator.

“To start with, there is a multiple amount of funding, public finance and policy signals being put in place right now that will accelerate the transition,” Steiner said. “For example, in terms of clean energy the European Green Deal translates into a €60 billion fund that is now being given to the minister of ecological transition in Italy to green Italy’s economy.”

Investment can’t just be made in one part of the world, particularly the part of the world that can afford it, he said.

“This is not a zero-sum game, as $100 billion from the rich world is actually going to leverage trillions of dollars of investment in clean energy in the global South,” Steiner said. “This is the co-investment proposition of our time. Now if we can make that equation work, we can not only achieve SDG 7 [the goal of ensuring universal access to clean, affordable and reliable energy], we can actually surpass it.”

ENGIE CEO Catherine MacGregor | United NationsGlobal energy company ENGIE is committed “to deliver on the decarbonization agenda” both for itself and its industrial clients, whom it helps to decarbonize their operations, ENGIE CEO Catherine MacGregor said. The company aims to be carbon neutral by 2045.

“I think very importantly we have to have shorter-term goals, which allows us to really track progress,” MacGregor said. “We are a private company and the task on us is to really be able to deliver progress, concrete projects.”

The company’s ability to collaborate with other private-sector actors as well as policymakers is important to meet the challenges facing the energy sector, she said.

“As an example of that, hydrogen is a massive potential solution for the hard-to-abate sector, but everything needs to happen in hydrogen — market design, policy, regulation — and here the private sector and government working together is so important,” MacGregor said.

Patricia Espinosa, United Nations Framework Convention on Climate Change | United NationsThe Paris Agreement provides the overall framework for action for the world, but then it also says every country  and every community needs to have a plan and those are the nationally determined contributions (NDC), said Patricia Espinosa, executive secretary of the United Nations Framework Convention on Climate Change (UNFCCC).

Pillai asked about “coherence” between the individual actions and the NDCs. NDCs represent pledges on climate action that seek to limit global warming to well below 2 degrees Celsius — and preferably 1.5 degrees — over pre-industrial levels.

“Ensuring that the individual actions by all stakeholders, especially the private sector, the financial community, of course, and the governments, provide the enabling environment is really the key to going from plans into implementation and reality,” Espinosa said.

Gender Equity

Arunabha Ghosh, Council on Energy, Environment, and Water | United NationsWomen-owned businesses have lower access to investments because they lack collateral and also face conscious and unconscious bias in investment processes, said Arunabha Ghosh, CEO of India’s Council on Energy, Environment, and Water.

“The general energy compact for us, the coalition believes, must be their means to harness and channel the support that women need to grow their businesses and to make them resilient,” Ghosh said. “One way of doing this is by leveraging investments from those interested in returns — not just on economic returns but on gender impacts, on results.”

Sheila Oparaocha, ENERGIA | United NationsThe World Bank is doing a lot of good work in gender equity, and the agreements made at the U.N. also need to be a catalyst to increase investments from both the public and private sectors to intentionally and directly invest in women’s businesses, Ghosh said.

Energy poverty is largely and most severely experienced by poor women globally, said Sheila Oparaocha, international coordinator and program manager for gender equity advocacy group ENERGIA.

“We find whether you are in a developing country, but even in the most economically advanced countries, we still find that women are marginalized from decision making and leadership in the energy sector,” Oparaocha said.

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Toxin Assessment Renews Environmental Justice Questions at Weymouth Compressor Station

Physicians, researchers and neighbors of a natural gas compressor station in Weymouth, Mass., are skeptical of an environmental assessment that found no public threat from oil, asbestos or arsenic contamination on the site, which formerly housed an oil tank and coal generating station.

Enbridge’s (NYSE:ENB) Algonquin Gas Transmission is accepting comments until Sept. 29 on the Phase II Comprehensive Site Assessment (CSA) conducted by consulting firm TRC Environmental Corp.

At a virtual public hearing Sept. 15, TRC explained the environmental sampling it conducted in response to the discovery of oil in subsurface areas near where an 11.2-million gallon fuel oil tank once stood on the site in the Fore River Basin, an industrial site for decades that is next to two state-designated environmental justice communities.

TRC said it conducted 140 soil borings, dug five test pits, installed 31 groundwater monitoring wells and collected more than 300 soil and 110 groundwater samples at the site of the Weymouth compressor station, which is built on man-made fill that includes bricks, dredged material, coal ash and “clinkers” — noncombustible residue from coal-fired generation. The site is adjacent to a public park, the Kings Cove Conservation Area, and Calpine’s Fore River Energy Center, a 731-MW natural gas combined-cycle generator.

‘No Significant Risk’

TRC Project Manager Matthew Oliveira said the sampling found the underground oil was not moving or a threat to groundwater and that no asbestos had been found in any of nine kinds of bricks sampled.

“[For] anyone visiting the site, there is no significant risk,” Oliveira said.

But many of the more than 40 people who attended the hearing expressed skepticism of the findings.

Phil Landrigan, director of the Program for Global Public Health and the Common Good at Boston College, said in an interview with NetZero Insider that asbestos-containing bricks used in the former coal plant are strewn around the peninsula where the compressor station is located.   

The state’s health impact assessment shows that residents in Weymouth have higher rates of cancer, pediatric asthma and cardiovascular and respiratory diseases. Concern that the compressor could exacerbate health threats have been heightened because the plant has experienced four emergency releases of gas since it went into operation in fall 2020. The most recent release was in May. In February, FERC responded to the earlier releases by issuing an order seeking input on whether it should reverse its approval of the compressor station. FERC’s order is being challenged by the station operator in appellate court. (See Algonquin Gas Appeals FERC Order on Weymouth Compressor.)

The Weymouth Compressor Station is adjacent to the Kings Cove Conservation Area. | TRC Environmental Corp.

Landrigan told NetZero Insider that TRC’s evaluation was flawed because it failed to consider the risk of fire and explosion that could cause widespread distribution of all the carcinogens in the fill dirt and incinerate houses in the area. “No question, fire and explosion is the biggest potential hazard associated with this facility,” he said.

Schools and homes for the elderly also sit close enough to the facility that if there was an explosion, they would be incinerated, according to research by the Greater Boston Physicians for Social Responsibility. One of the schools caters to children with special needs and limited mobility, making an evacuation difficult.

“I think one of the reasons that industries, including this compressor station, have been sited there is because it is a low-income, blue collar, 46% minority community with limited political power,” Landrigan said. “I just think it’s morally and ethically wrong.”

Since Enbridge paid TRC for the site assessment, the findings must be “very carefully assessed and possibly discounted,” Landrigan added.

Oliveira, responded at the meeting that the Massachusetts Bureau of Waste Site Cleanup does not require an assessment of the potential risk of explosion.

Explosion Fears

Fresh in the minds of many of the public commenters and questioners during the public meeting on the impact assessment were the 2018 Merrimack Valley explosions, which killed one, injured 20 and caused 80 fires, displacing 8,000 people.

The pressure in interstate pipelines such the Algonquin Pipeline system connected to the Weymouth compressor ranges from 200 to 1,500 pounds per square inch (psi). That pressure is more than in the pipelines that exploded in the Merrimack Valley, which were pressurized at 0.5 psi, Landrigan said.

Geologists have found that human-made land, such as where the compressor station was built, is not as stable because it sinks over time, said Brita Lundberg, chair of the board of Greater Boston Physicians for Social Responsibility. Enbridge also built the pipelines connected to the compressor station with the wrong material, which corrodes in contact with salt water. According to residents in the area, Enbridge is in the process of digging trenches to uncover gas pipes and install cathodes to protect them from corrosion.

The Metropolitan Area Planning Council (MAPC), a county government agency based in Boston, also conducted a risk hazard assessment that did not consider the risk of fire or explosion. Marc Draisen, executive director of MAPC, has since backtracked on its risk assessment, acknowledging it was too superficial given the potential for explosion, malfunction or “serious mechanical or oversight failure,” though MAPC as an agency is not required to look into the impacts of potential explosions.  

“MAPC wishes to reiterate its opposition to the natural gas compressor currently under construction in Weymouth,” according to the statement from Draisen, which also highlights MAPC’s lack of engagement with environmental justice communities in its assessment.

However, Enbridge spokesperson Max Bergeron said in a statement to NetZero Insider that “there are significant differences between interstate natural gas pipelines designed and certificated to safely operate at greater pressures.”

“Local natural gas distribution infrastructure, which may be designed with different materials, generally operates at lower pressures,” Bergeron said in the statement. The Merrimack Valley explosions involved “local natural gas distribution infrastructure, which is materially different from interstate natural gas infrastructure, including compressor station facilities.”

Arsenic Contamination

Spectra Energy, a natural gas transmission company that merged with Enbridge in 2017, said during a Weymouth Conservation Commission meeting in 2019 it found that arsenic levels in the coal ash are above state and federal standards.

Lundberg met with the Massachusetts Department of Public Health (DPH) about the arsenic contamination and the potential exacerbation of hazard risks with the natural gas facility before it was built. But the state agency has been largely absent in recent discussions about the contaminants and did not know the site had arsenic contamination until it was approached by the Greater Boston Physicians for Social Responsibility, Lundberg said.

DPH did not respond to requests for comment.

Shellfish in the water next to the compressor station are now known to be contaminated with arsenic, Lundberg said. But residents, particularly low-income or non-English speaking residents, still fish there because they do not know the water and the fish are full of toxins, as neither Enbridge nor the DPH have put up signs warning people.

The compressor station was built on a public easement, so members of the public can still walk near the property and have legal access to the water.

Resident Robert Kearns, who uses the park, said at the hearing that Algonquin is “not being a good neighbor” in refusing to post warning signs.  

Kearns also said Algonquin should “clean up the beach as well as fulfill the promises that were made for the west waterfront to be a public park and not be calling us trespassers for using that area because that was a condition for the siting of the [Calpine] power plant.”  

Oliveira apologized for describing users of the area as trespassers, acknowledging it was “maybe not the best use of the term.”

“What’s really needed here is a careful evaluation by an outside agency,” Landrigan said. The U.S. Environmental Protection Agency has grounds for being involved, Landrigan added, as the peninsula juts out into the Boston Harbor. Arsenic and asbestos could have leaked into that area as well, he said.

Next Steps

TRC said it will respond to comments on its assessment and provide any updates by Nov. 8. TRC’s “phase three remedial action plan” is due July 28, 2022.

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Mayflower Wind Pledges $81M for Economic Development in OSW Bid

Mayflower Wind has submitted a 1.2-GW bid in the latest Massachusetts offshore wind solicitation with a commitment to spend up to $81 million for economic development.

The joint venture between Royal Dutch Shell (NYSE:RDS.A), EDP Renewables and ENGIE said Thursday that it submitted multiple bids, the largest of which would interconnect 1.2 GW at Brayton Point in Somerset. Additional bid sizes were not disclosed.

“The bids we submitted were formulated after months of conversations with local stakeholders who shared with us their vision for the future of the offshore wind industry,” Mayflower Wind CEO Michael Brown said in a statement. “We took those conversations very seriously and developed packages that incorporate their feedback and support each of their diverse groups.”

Mayflower is one of only two developers that submitted bids in the 83C iii solicitation announced in May. Vineyard Wind said last week that it submitted bids for 800 MW and 1.2 GW under the name Commonwealth Wind. (See Partners Behind Vineyard Wind Divvy up Leases.)

The solicitation, which is the third call for offshore wind in Massachusetts, requested proposals of between 400 MW and 1.6 GW. Mayflower secured a power purchase agreement under the state’s second call with its 804-MW project. The Massachusetts Department of Energy Resources said in an August 2020 brief that the proposal had the lowest price of 28 received for the round.

Mayflower is developing a 127,000-acre lease area (OCS-A 0521) off the coast of Massachusetts that it won through a competitive sale held by the Bureau of Ocean Energy Management in 2018. The developer says the lease area has 2 GW of generation potential.

Workforce and Equity

Under the economic development program Mayflower is planning for its new bids, the developer will focus on building out the offshore wind supply chain and workforce. It also plans to make “significant investments” in ports, businesses and infrastructure, according to a company statement.

If Mayflower wins a contract in the new solicitation, it also will create an operations and maintenance port in the city of Fall River, at the Borden & Remington Ironworks complex.

“Our O&M port in Fall River and the National Offshore Wind Institute in New Bedford, which we are proud to support, will be twin anchors for a vibrant and growing offshore wind industry on the South Coast,” Brown said.

Fall River, which is opposite Brayton Point across Taunton River, was among 28 environmental justice communities identified in a recent state report as being a priority location for offshore wind workforce development. (See Mass. Has Significant OSW Workforce Gaps for 1.6 GW Pipeline.)

“We will get the benefit of the regular transition point for the crew and staff when they go out to work on the project,” Fall River Mayor Paul Coogan told NetZero Insider. “We could have 20 to 25 permitted jobs to start, depending on how many megawatts Mayflower Wind is awarded, and then we’ll be able to expand from there.”

The developer, Coogan added, is taking a 15-acre strip along the city’s waterfront, but there also will be space for expansion if needed. The complex, he said, has a working chemical company on it now and features a train track, close proximity to the highway and easy access from Mount Hope Bay.

In its bid, Mayflower committed to enabling disadvantaged businesses and incorporating diversity, equity and inclusion principles into its activities. The developer said it will target a portion of its spending for businesses certified by the Massachusetts Supplier Diversity Office to encourage minority- and women-owned businesses to enter the offshore wind supply chain, according to the bid document.

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Texas PUC Directs Transmission Construction in Valley

Texas regulators exercised their newfound regulatory authorities Thursday in bypassing ERCOT’s stakeholder process and directing three utilities to add a second 345-kV circuit to an existing transmission line in the frequently constrained Rio Grande Valley.

Citing the its “broad, statutory authority to order construction that ensures safe and reliable power,” the Public Utility Commission ordered AEP Texas (NASDAQ:AEP), South Texas Electric Cooperative (STEC), Sharyland Utilities and Electric Transmission Texas (ETT) to add a second circuit to their portions of the 385-mile line that circles the region.

Utility representatives said it will take almost three years to add the second circuit. Given the commission’s demand for an accelerated timetable, the project will still be completed before ERCOT’s planned construction of a new 345-kV line in the Valley. The grid operator is recommending the project, which has a $1.28 billion price tag, and plans to get board approval before the year is up. (See ERCOT Finds 345-kV Solution for Valley Constraints.)

Woody Rickerson, ERCOT vice president of grid planning and operations, said the greenfield project will meet future load growth and generation development through 2040 and address reliability and stability constraints. Seven of ERCOT’s 16 generic transmission constraints are in the Valley, which sits at the edge of the Texas Interconnection with limited long-distance transmission circuits.

Adding a second circuit and new facilities to close the loop on an existing 345-kV line from San Miguel down to North Edinburg and then over to Palmito will wring an additional 300 MW of capacity for the region, where the gird operator has been having trouble keeping up with load growth.

“We don’t want to see anything delay” the project, Rickerson said. It “would get us out of this just-in-time [cycle] … and would be a step change from what we’ve done in the past. This is a kickstart all the way to 2040.”

Commissioner Will McAdams compared the project’s cost to the multibillion-dollar 345-kV Competitive Renewable Energy Zone in West Texas that connected renewable resources to the state’s urban population centers.

However, adding the second circuit will still cost up to $500 million, according to the utilities’ projections. Sharyland estimates it will cost $106 million to $128 million for its 47-mile portion and to close the loop, while STEC forecasted it will spend $31.8 million to add to its 42 miles.

ETT, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries, said its portion will run from $311 million to $350 million and that AEP’s facilities will cost $28.9 million.

As the commissioners struggled to understand the short-term project’s costs, AEP Texas Project Manager Wayman Smith explained that while the original line was double-circuit-capable, the towers did not have arms on both sides. He said additional structures also have to be added when the line makes a severe turn, as the turn can’t be made with circuits on both sides of the tower.

Smith said some 70 miles of its lines already have conductors hanging and arms because they were used to interconnect three different wind farms.

“We’re not going to put the Valley at risk,” Smith said. “That has put us in a bind, because now we have infrastructure that should have been built with two circuits from the beginning.”

Commissioner Lori Cobos said the utilities will still be expected to meet regulations’ ratemaking principles and standards. “This is not a blank check.”

Offer Cap Could be Halved

The PUC has given ERCOT stakeholders until Thursday to file comments on whether halving the $9,000/MWh high systemwide offer cap (HCAP) to $4,500/MWh is an “appropriate level” and whether the change will have any consequences on the value of lost load, currently set at the HCAP when the latter is in effect (52631).

McAdams, who filed a memo suggesting the action, said he did so in the “interest of market certainty” and to “assuage consumer concerns” by putting in place safeguards that market participants and residential consumers can rely on as ERCOT, hoping to avoid a repeat of February’s devastating storm, heads into the winter months.

Last winter’s storm “was traumatizing. We recognize that,” McAdams said. “The next winter after [it] will be remembered by consumers of all classes.”

The comment period would begin a process that could have a new HCAP in place by December. The commission could also take up the issue during its next market redesign work session on Oct. 14.

“This isn’t market redesign. This is market design,” McAdams said.

The HCAP is currently set by rule at $2,000 after it remained at $9,000 for too many consecutive hours during the storm as ERCOT battled to meet demand with about half of its available generation. That resulted in about $50 billion in market transactions during the week of the storm, sending several retailers and one cooperative into bankruptcy. The cap is set to revert back to $9,000/kWh on Jan. 1.

In ERCOT’s energy-only market, the price cap is designed to incent generators to produce power during scarcity conditions. While reducing the cap would cut into generators’ profits, Stoic Energy’s Doug Lewin, a consultant for 16 years in the market, said even they have filed comments urging the cap be reduced.

“This is the one thing that is almost certain to happen,” he told RTO Insider. “I think politically, it has to happen.”

McAdams has also suggested opening a rulemaking to decouple demand response resources from the emergency energy alert levels, identify a more conservative trigger for deploying emergency response service (ERS) resources and consider raising the ERS resources’ spending limit from the current $50 million.

PUC Chair Peter Lake said the commission will consider and take action on the feedback it has gathered in recent months on proposed changes to the operating reserve demand curve, ancillary services and other market features.

“We run the risk of putting Band-Aids on bullet holes,” he said. “The legislature has asked us to look at ancillary services and new products, but also to ensure broader reliability in the marketplace. I’m asking the stakeholder community to think about the kind of substantial changes to the ERCOT market’s normal functions … that will ensure the resources and economics of the ERCOT model go to generating resources that provide reliable power in any form or fashion.”

Debt Securitization on the Calendar

The commission said it will take up an order securitizing debt from the winter storm following an unopposed settlement in one of two related dockets.

Vistra’s Amanda Frazier said during last week’s Gulf Coast Power Association’s Fall Conference that parties to ERCOT’s request for a debt-obligation order to finance $2.1 billion in market debt have filed a settlement. She said the agreement addresses three key issues: the methodology and allocation of securitization proceeds among load-serving entities; how LSEs would document their exposure; and establishing opt-out provisions for municipalities and cooperatives (52322).

“We put a lot of work into the agreement. PUC staff really helped drive that outcome,” Frazier said.

McAdams said it would be prudent to give staff additional time to cover the agreement’s finer points and issues before issuing a final order. Staff has also scheduled time next week for the commissioners to discuss the settlement.

The second securitization docket proposes to finance $800 million to replenish ERCOT funds used to reduce short pays to the market (52321). As of Sept. 1, the market was still short almost $3 billion.

ERCOT filed its debt-obligation requests in August, and a three-day hearing was held earlier this month. (See “Securitization Hearings Conclude,” PUC Workshop Takes First Stab at Market Changes.)

PUC to Intervene in ANOPR

Following staff’s recommendation, the commission will intervene in FERC’s Advanced Notice of Proposed Rulemaking to reconsider its regulations on regional transmission planning, cost allocation and generator interconnection processes (RM21-17). (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

ERCOT is not within FERC’s jurisdiction and serves about 90% of Texas’ load. MISO, SPP and WECC all oversee portions of the remainder.

Noting MISO is currently working on long-term transmission-planning issues and cost-allocation measures, Cobos, who represents the PUC on the Organization of MISO States, said, “I think it’s important we get involved in these issues at the federal level.

“We do need transmission to ensure reliability in those areas of the state that are not within ERCOT,” Cobos said. “Those are very important areas of the state as well, and we need to make sure those ratepayers are not being allocating costs for other parts of those ISOs and RTOs that they’re not getting benefit from.”

Staff proposed the commission intervene in the FERC docket, direct them and outside counsel to monitor the proceeding, and participate in relevant discussions with SPP and MISO state regulators (41211).

“These regions, they’re not easy games to play in,” Commissioner Jimmy Glotfelty said. “Us getting in there and building relationships — getting them to understand what we want and what we need — is important.”

In other actions, the PUC:

      • extended through May 2022 ERCOT’s requirement to make public generator forced and maintenance-level outages and derates within three operating days. Existing protocols have kept that information confidential until 60 days after the operating day. The commission in June ordered the grid operator to report that information after an above-normal number of outages forced a conservation call. The grid operator is working on a pair of protocol changes that will set up timely automated public reporting of outages (52266).
      • gave Executive Director Thomas Gleeson authority to solicit nominees to the Texas Energy Reliability Council, recently created by legislation. The council will be responsible for ensuring that Texas’ electric and energy industries meet “high-priority human needs,” address “critical infrastructure concerns” and improve their coordination and communication. It will comprise eight members, five of which will individually represent dispatchable power entities, transmission and distribution utilities, retail electric providers, municipalities and cooperatives. Three others will speak for energy sectors not otherwise represented (52557).
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Counterflow: Participant Funding and Its Discontents

As we contemplate throwing hundreds of billions at new transmission in order to interconnect new renewable generation — $2,360 billion according to the Princeton net-zero study[1] — here’s a cautionary note on a central target of the Advance Notice of Proposed Rulemaking (ANOPR) FERC announced in July:[2] participant funding.

Participant Funding: ABCs

Participant funding has been a foundational principle in all the RTOs[3] — dating back more than 20 years in PJM for example.[4] Stated simply, a new generator pays for whatever upgrade of the grid is needed to maintain reliability with  the interconnection of its project. If the new generator causes a reliability risk, a.k.a. violation, that didn’t exist before, the new generator pays to relieve the violation.

Economics

This principle makes so much sense that even an economist can explain it. Take, for example, a developer pursuing two potential wind projects of the same size and capacity factor; the first would cost about $110 million to build and the second would cost about $90 million. The first would necessitate $10 million in grid upgrades in order to maintain reliability, and the other would cost $50 million in grid upgrades. If the developer has to consider the total cost of its alternative projects, then it will opt for the first project at a total cost of $120 million instead of $140 million for the second. If, instead, others (transmission customers for example) will pay for the upgrades then the developer will opt for the second project at a total cost to it of $90 million instead of $110 million. The generator saves $30 million on its project; transmission customers pay $50 million for the upgrades; and the difference of $20 million is a deadweight loss to society. Not good.

And Fairness

Not only is participant funding economic, it is also fair. Other than paying for any necessary upgrades, the new generator gets access to the grid for free; transmission customers and past generators paid (and pay) for the existing grid. Transmission customers pay for the transmission service from the generator to load. And transmission customers will pay for any upgrades needed in the future even if the new generator contributes to the need for such future upgrades.

The discontents like to say (often in the case of the ANOPR) that a new generator’s upgrades can provide increased transmission capability, a.k.a. “headroom,” that provides system benefits like lower energy costs and higher reliability. What this ignores is that the new generator gets the benefit for free of existing headroom paid for by transmission customers and past generators. To illustrate this, a new generator’s project could increase loading on, say, 10 transmission lines (remembering that this is a grid where new generation injected at a single point is distributed across many lines[5]). On, say, eight of the 10 lines there is existing headroom, paid for by others, such that the project does not cause a reliability violation on those lines. The generator gets to use that headroom for free.[6] On the other two lines there are reliability violations, and the generator pays for upgrades to relieve those violations. Manus manum lavat, hand washes hand.

Speaking of fairness, let’s not forget the many, many billions that investors have contributed to construct and interconnect the existing generation that today provides us reliable electric service at reasonable cost and at declining carbon emissions. Changing the rules now to favor new generation investment, at the disadvantage of past generation investment, would be unfair.

System Benefit Claims

Even if the above weren’t enough — which it ought to be — we need to carefully scrutinize claims of system benefits. Let’s remember at a basic level that whatever energy savings benefit comes from new generators at uneconomic locations, that we’d get roughly the same benefit from new generators at economic locations. Why pay extra to subsidize uneconomic generation?

And a few words about the latest study to claim benefits for customers as a reason to abandon participant funding: A study by the ICF consultancy paid for by the American Council on Renewable Energy (ACORE).[7] In a nutshell ICF started with a pool of 663 network upgrades in SPP and MISO, and selected 12 (2%). One criterion for selection was that the upgrade capital cost be low relative to the potential generation that would be connected; it’s unclear how that might have biased the results. In any event, if you add up all the costs of the 12 upgrades,[8] the total is about $3.3 billion. If you add up all the claimed benefits to load, the total is about $990 million. Somehow these results are supposed to show that we should get rid of participant funding and just bill load for the $3.3 billion. So load would pay $3.3 billion and in return get $990 million of benefits. Such a deal!

The study also ignores the benefits that new generation gets for free from transmission that was paid for by others, as discussed in the preceding section. Is the benefit that new generation gets from others more than the benefit it provides others? I don’t know, and neither does anyone else.

As for the assertion: more transmission = more reliability, this is specious. The grid is planned to satisfy reliability criteria. More transmission facilities driven by the need to interconnect remote generation (the ANOPR’s premise is that the new generation we need is remote) may, or may not, increase reliability. All else equal, the longer the transmission line the less the reliability (think longer lines’ increased exposure to extreme weather and, yes, more squirrels).

Remoteness

The ANOPR tried to come up with a reason why the last 20 years of RTOs developing — and FERC blessing — participant funding should be thrown away. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

The lead claim seems to be that since Order No. 2003 was issued, “the composition of the generation fleet has rapidly shifted from predominately large, centralized resources to include a large proportion of smaller renewable generators that, due to their distance from load centers, often require extensive interconnection-related network upgrades to interconnect to the transmission system. The significant interconnection-related network upgrades necessary to accommodate geographically remote generation are a result that the commission did not contemplate when it established the interconnection pricing policy for interconnection-related network upgrades.”[9]

I count four fatal flaws in this thesis. First, I can’t find anything in Order No. 2003 that says participant funding turned on a lack of remote, smaller generation, or that the commission didn’t contemplate the possibility of remote, smaller generation needing “extensive” network upgrades. Second, conditions on the ground when Order No. 2003 was issued don’t support the thesis, as there already were wind projects, such as 30 listed in the PJM queue.[10] Third, currently proposed renewable projects aren’t necessarily remote from load centers as this PJM slide shows.[11] Fourth, perhaps most fundamental, if new renewable generation is relatively remote and if that can cause “extensive” network upgrades, then all the more reason that such generation not be interconnected without considering total cost, including upgrades.

Wrapping Up

Participant funding was the right idea 20 years ago. And it still is.

[2] Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 176 FERC ¶ 61,024, 86 Fed.Reg. 40266 (2021).

[3] The ANOPR states at P 105: “Over time, each RTO/ISO sought, and the Commission accepted, independent entity variations to adopt some form of participant funding rather than the crediting policy.”

[4] PJM Interconnection, L.L.C., 87 FERC ¶ 61,299, at page 17 (1999) (“… generators will be required to pay the full cost of grid expansion …. this type of proposal forces the developer to consider the economic consequences of its siting decisions when evaluating its project options, and should lead to more efficient siting decisions.”).

[5] A good introduction to the basic concepts is here, https://www.e-education.psu.edu/ebf483/node/513.

[6] To get a little technical, take a line that has peak loading of 70 MVA, and a maximum line rating of 100 MVA. Suppose the project increases the peak loading to 85 MVA. Because that is still below the maximum line rating of 100 MVA, the new generator pays nothing for increasing the peak loading.

[8] Exhibit 2 on page 5.

[9] ANOPR at P 100.

[10] https://pjm.com/planning/services-requests/interconnection-queues, select “Wind” as fuel and the “Dates” tab for queue date.

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Extreme Sea Levels to Occur More Frequently, Study Says

The type of extreme sea levels previously expected to occur roughly once every 100 years could happen annually by 2100 due to global warming, a study by the Pacific Northwest National Laboratory and several other institutes has concluded.

The results were published last month in the journal Nature Climate Change.

The PNNL-led study reached the same conclusion as a 2019 Intergovernmental Panel on Climate Change report. However, the 2021 report studied significantly more seaside locations than the 2019 study, said Claudia Tebaldi, a PNNL staff scientist who coordinated the writing of the 2021 report. Tebaldi works at the Joint Global Change Research Institute, a partnership between PNNL and the University of Maryland.

“Our [2021] results are stronger,” Tebaldi told NetZero Insider.

The 2021 study looked at scenarios of the Earth’s average temperatures increasing from preindustrial averages by 1 degree through 5 degrees Celsius by 2100. So far, average temperatures are 1 degree above preindustrial levels. There is significant scientific speculation that the averages could increase by 1.5 to 2 degrees by 2100.

“We know we’re going to hit 1.5 already,” Tebaldi said.

The 2021 study looked at 7,283 shoreline locations around the world. Its computer modeling concluded that extreme spikes in seas levels that would have been predicted to occur every 100 years would likely take place annually in about half of the locations by 2100.

Fluctuations in sea levels are tied to melting polar ice, currents and tides. Colder water coming from melted polar ice has ripple effects on currents, Tebaldi said.

The annual sea level extremes are more likely to occur in the Northern Hemisphere’s lower latitudes, she said.  The most likely affected areas will be the Southern Hemisphere, the Mediterranean Sea, the Arabian Peninsula, the southern half of North America’s Pacific coast, Hawaii, the Caribbean, the Philippines and Indonesia.

“At vulnerable locations, high [extreme sea levels] can constitute severe hazards, causing extensive damages to both human settlements and coastal ecosystems when natural and engineered defenses are overtopped or breached,” the study said.

Tebaldi said the next research step will likely include numerous scientific ventures examining the individual spots facing an increased likelihood of rising sea levels, determining each area’s vulnerabilities and preparing local communities to deal with the changes.

Meanwhile, the rising sea levels and changed currents will likely affect the direction and frequency of storms in these areas, she said, adding that future studies also need to address the potential changes in storms.