CHARLOTTE, N.C. — SERC Reliability’s Tim Ponseti said Wednesday that the regional entity’s stakeholders will be “well represented” in the group advising the ERO on the congressionally mandated Interregional Transfer Capability Study (ITCS).
“We … have six major reliability coordinators at play within the SERC footprint, and each of those are around 45,000 MW [of] peak load or more,” Ponseti, the RE’s vice president of operations, said at SERC’s Board of Directors meeting Wednesday. “So you can see the significance.”
The ITCS was a significant focus of the meeting, reflecting the urgency with which the ERO views the task. Congress ordered the study in June as part of the Fiscal Responsibility Act (FRA), requiring NERC and the REs to submit a report to FERC by December 2024 on the total transfer capability between neighboring regions, additions to transfer capability that could improve grid reliability and recommendations to meet and maintain total transfer capability. (See FERC Approves NERC Transfer Study Funding Request.)
SERC and the other regions are central to the study process, Ponseti said as he explained the organization of the study. The ERO Executive Leadership Group will be in overall control of the project; Ponseti said he and his counterparts from other REs will serve on this body, led by Mark Lauby, NERC’s chief engineer.
Two teams will serve below the executive group: the ERO Project Team, led by NERC Director of Reliability Assessment and Performance Analysis John Moura, and the ITCS Advisory Group, comprising industry stakeholders who will provide advice and input on the study scope, approach, results and recommendations. Ponseti said the makeup of the advisory group should be announced “in the next week or two,” and that SERC stakeholders will comprise “a fourth or a fifth” of participants.
The FRA specified that the ERO’s study is to be based on the transmission planning regions identified in FERC Order 1000. However, Ponseti noted that the order “came out some time ago” and several of the regions have “shifted, merged, combined [or] split” in the following years. He did not go into detail about how the team would account for these changes, saying only that members would “be taking it as we feel appropriate from an electrical standpoint.”
Congress mandated that the ITCS is to be based on the transmission planning regions identified in FERC Order 1000. | SERC Reliability
While NERC and the regions are moving ahead at full speed with the study, there are potential stumbling blocks ahead. Rebecca Poulsen, SERC’s assistant general counsel, noted that Sen. Dianne Feinstein (D-Calif.) introduced a bill in July (S.2443) containing language that would repeal the order for the ITCS in the FRA.
Poulsen said that “we’re not concerned about” the prospect of the bill passing before the deadline for the study arrives. But she said that it was important to remember “there are still some political discussions going on about whether the study should be done or who should be doing the study.”
Director Roger Clark, of Associated Electric Cooperative Inc., said he recognized that “transfer capability is a tool to solve reliability” and supported the aims of the study. However, he also pointed out that “transfer studies have been done forever” and that transfer capability is just a single part of an equation that also must consider elements such as the cost of building the required transfer capacity. Noting that Ponseti said the study would not recommend specific projects, he asked if any “cost allocation implications [would] come into this process.”
“It’s certainly not going to be the objective of this … study to say, ‘Build a 5-million-kV line from point A to point B.’ It’s going to be broader than that,” Ponseti replied. “It will say, ‘We need 2,000 MW of additional transfer capability, or 5,000 MW,’ [for example]. The how, when, why and how it gets paid for will be left for future discussion.” Later he added that “it’s not just megawatts.”
Ponseti also emphasized that the ERO hopes for the ITCS to have a long-term impact, echoing Moura’s assurance earlier this year that the intent is “not just to submit to FERC and do nothing” in the aftermath. (See NERC Confident in Ability to Deliver ITCS On Time.)
NERC’s Reliability and Security Technical Committee decided Wednesday to suspend planning for the impact of an electromagnetic pulse (EMP) that could result from a nuclear attack.
The RSTC voted to disband its EMP Working Group after four years, finding that other risks to grid reliability have taken precedence, diverting resources and expertise from the working group and causing participation to drop. (See p. 55 of meeting materials.)
The electromagnetic pulse caused by the detonation of a nuclear weapon can disrupt or damage electronic circuitry. The task force was formed following the Electric Power Research Institute’s 2019 report on EMPs, which concluded that a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers have warned of.
President Trump in March 2019 ordered a governmentwide effort to protect against this threat. NERC responded by establishing the EMP Task Force, and later the EMP Working Group.
At Wednesday’s RSTC meeting, the working group’s former chair, Aaron Shaw of American Electric Power, said initial response was strong — as many as 70 to 80 people were participating in the group regularly. (See Standing-room Only for NERC EMP Meeting.)
But other issues bearing on grid reliability began to take priority, he said, including inverter-based resources, cyber and physical attacks, distributed energy resources and extreme weather.
“What we started noticing in 2022 is that EMP fell off the Risk Report as an emerging risk that needed to be addressed,” Shaw said. Utilities diverted subject-matter experts to other emerging issues, which led federal agencies to disengage as well.
“Very quickly we had all these monthly calls with all these sub-teams and nobody was participating,” he added.
Some attendees at Wednesday’s meeting questioned the move to stop assessing the EMP threat, given current international tensions.
There is a lot of work yet to be done, Shaw agreed, but the momentum to do it has been lost. Individual utilities and agencies can continue on their own.
The vote to disband was 93% to 4%.
The working group can be reconvened relatively quickly if needed. Its work to date will be archived for industry reference, but because it is not complete, it will not be approved or endorsed by the RSTC.
White Paper Green Lighted
The committee also approved the Inverter-Based Resource Performance Subcommittee’s white paper on functional specifications for grid-forming battery energy storage systems connected to the bulk power system. (See p. 95.)
The paper is intended to help transmission planners determine whether interconnected BESS can be considered a grid-forming resource based on its performance.
At the RSTC’s June meeting, the paper bogged down in a debate over whether its wording connoted a suggestion or a directive. It was tabled then, and numerous technical revisions subsequently were made.
Even so, commenters Wednesday suggested fine-tuning the wording to make it clear that this is a white paper, not a directive.
The RSTC voted to approve the paper as it was revised, 90% to 7%.
White Paper Red Flagged
Semantics were an issue again Wednesday on another white paper on using cloud-based computing technology in grid operations. (See p. 236.)
Several speakers — some of them with self-deprecating remarks about their age or understanding of cloud technology — said they are not comfortable with the idea of combining critical operations into a single off-site location.
Not surprisingly, they also did not want it to appear that the RSTC was endorsing a move to cloud-based operations by offering guidance for doing so.
Discussion was paused for lunch, during which staff made revisions. When the meeting reconvened, objections were raised about the placement of a period in a sentence and a plural-vs.-singular construction.
The white paper was rejected in a tie vote.
Further revisions will be made to address the concerns and the matter will be put to a vote again via email.
For the world to have any hope of limiting climate change to 1.5 degrees Celsius, well-off countries around the globe must stop burning coal by 2030 and cut emissions economywide to net zero no later than 2040, according to the United Nations’ Accelerated Climate Action Agenda.
Those aggressive goals were the centerpiece of the opening plenary of the UN Climate Ambition Summit in New York City on Wednesday, with Secretary General António Guterres calling out governments and business for “foot dragging, arm twisting and the naked greed of entrenched interests” that have slowed efforts to curb greenhouse gas emissions.
“Humanity has opened the gates of hell,” Guterres said, reeling off a growing list of climate disasters: floods, wildfires and extreme heat. “Climate action is dwarfed by the scale of the challenge. If nothing changes, we are heading towards a 2.8-degree temperature rise, towards a dangerous and unstable world.”
Setting the stage for the UN Climate Conference (COP 28) in the United Arab Emirates in December, Guterres also called for an end to subsidies for fossil fuels worldwide, which the International Monetary Fund (IMF) pegged at $7 trillion in 2022.
UN Secretary General António Guterres | United Nations
Instead, the accelerated agenda shifts fossil fuel subsidies to renewable energy and ends all licensing and public and private funding for new oil, coal and gas. Targets for developing nations are 2040 for coal phaseout and 2050 for economywide net zero.
“Governments must push the global financial system towards supporting climate action, and that means putting a price on carbon and overhauling the business models of multilateral development banks so that they leverage far more private finance at a reasonable cost to developing countries,” Guterres said.
Businesses and financial institutions also must embark on true net-zero pathways, he said. “Shady pledges have betrayed the public trust … using wealth and influence to delay, distract and deceive, and this is shameful.”
Part of the UN General Assembly, the Climate Ambition Summit plenary laid out the issues and potential flashpoints that will resurface at COP 28 as the nations that signed the Paris climate accords in 2015 face the first official global stocktaking of the world’s progress on climate, required by the agreement.
But concerns about progress at COP 28 already are high in some quarters as the U.A.E. has named Sultan Ahmed Al Jaber, CEO of the Abu Dhabi National Oil Co., as the conference president. Speaking at a climate conference in Brussels in July, Al Jaber called for an accelerated “phasedown” of fossil fuels, as opposed to a phaseout, supported by a tripling in the deployment of renewables and a doubling of energy efficiency.
“Phasedown” also was the language used by G20 energy transition ministers in the final document coming out of their meeting in India in July, in which disagreements were noted about the extent and nature of any future phasedown.
Pairing emission cuts with increased renewables and energy efficiency is gaining support. Ursula von der Leyen, president of the European Commission, said the European Union is working with Al Jaber, Kenya, Barbados and other countries to build a global consensus on the renewable energy and energy efficiency targets ahead of COP 28.
Fossil Fuel Nonproliferation
Guterres billed the summit as an event to recognize the efforts of the nations and organizations moving ahead on ambitious climate action, while also signaling frustration with major polluters, including the United States and China, which were not invited to speak.
However, California Gov. Gavin Newsom (D) earned strong applause for his indictment of major oil companies, following the state’s suit filed Friday against Exxon, Shell, Chevron, ConocoPhillips, BP and the American Petroleum Institute, an industry trade group. (See Calif. Sues Oil Majors over Climate Impacts.)
California Gov. Gavin Newsom | United Nations
“It’s time for us to be a lot more clear this climate crisis is a fossil fuel crisis,” Newsom said. “It’s not complicated. It’s the burning of oil; it’s the burning of gas; it’s the burning of coal, and we need to call that out. For decades and decades, the oil industry has been playing each and every one of us in this room for fools. They’ve been buying off politicians. They’ve been denying and delaying science and fundamental information that they were privy to that they did not share.”
Echoing Newsom, Chilean President Gabriel Boric said, “We have to leave fossil fuel behind, and that, in very specific terms, means that we also have to react to the greenwashing that major businesses are undertaking. They continue with that greenwashing, and they’re stepping it up. In some cases, their greenwashing efforts are supported by countries.
“If we’re not able to make these groups yield to our will and to make them yield to the will of the international community as expressed by the leaders here present and by the activists here … the truth is that we won’t hit our targets.”
Prime Minister Kausea Natano of the Pacific island nation of Tuvalu, believes the way forward must include “a comprehensive, multilateral framework that addresses the climate crisis at each root cause. A negotiated fossil fuel nonproliferation treaty would complement the Paris agreement and ensure a global [energy] transition.”
Von der Leyen also promoted wider adoption of carbon pricing as a way to raise money to support clean energy transitions in developing nations. In addition to cutting emissions 55% by 2030, the EU also will work with the UN “to have at least 60% of global emissions covered by carbon pricing by 2030,” she said.
“Today, it’s only 23% [of emissions] that are covered, and this brings in revenue already of $95 billion. Just imagine [if] we could cover 60% of global greenhouse gas emissions, the amount of revenues that we would get to invest in low- and middle-income countries.”
Restructuring Global Finance
Canadian Prime Minister Justin Trudeau credited his country’s carbon pricing with GHG emissions that have been trending down since 2019, even as Canada continues to be a major fossil fuel exporter.
Canadian Prime Minister Justin Trudeau | United Nations
The country has a plan for cutting emissions 40% by 2030, that “goes sector by sector, laying out exactly how we will cut our emissions,” he said. “By the end of the year, we will be announcing our framework to cap emissions from the oil and gas sector.”
Regulations on cutting methane emissions from the oil and gas sector 75% below 2012 levels also are being prepared and “will be designed to help us exceed this already ambitious target,” he said.
Gustavo Petro, president of Colombia, another major fossil fuel exporter, argued for a more radical approach to the phaseout of oil and gas, recognizing first the enormous economic and political power of the industry.
Even the goal of net zero is not viable, Petro said, because “the natural absorption capacity of the planet and the oceans, the forests, the jungles is decreasing, so net zero doesn’t really exist.”
Phasing out fossil fuels will require changing the economic structures of countries, like Colombia, that are dependent on the industry, Petro said. “Capital needs to be essentially separated from economic interests where fossil fuels are concerned.
“You need to compensate oil- and gas-producing countries for plugging their deposits, [for] no longer plundering them,” he said. “Rather you need to give them money for mitigation and adaptation. That finance won’t come from a private capital market. These major financial resources can only be produced if we restructure the global financial system.”
A strong advocate for the restructuring of global finance, Mia Mottley, prime minister of Barbados, said, “The reality is that developed countries are going to have to find new mechanisms and new forms of carbon taxes while looking [to] ensure that there is not consequential impact that is incapable of being borne on cost of living. …
“Equally, developing countries will need a new mechanism to reduce the costs of hedging the billions of inward investment required,” she said. “We believe that the [tripling] of the multilateral development bank lending is critical.”
Prime Minster Mia Mottley of Barbados | United Nations
Mottley also hammered on the importance of a well-capitalized loss and damage fund, to compensate developing countries with low GHG emissions for the damage they’ve sustained from climate change. The establishment of a loss and damage fund was a major outcome of COP 27 in Egypt last year, but getting countries or companies to contribute to the fund will be one of the key challenges at COP 28.
“It is painful to continue to see that you are asking us to increase borrowing to build resilient infrastructure for something that we did not do,” Mottley said. “And then at the same time, you want to ensure that you have a loss and damage fund that does not have the adequate means for grant funding to be able to help countries to rebuild. It is unconscionable.”
The New England Transmission Owners outlined a proposal for a new asset condition project database at ISO-NE’s Planning Advisory Committee on Wednesday.
The proposal came in response to requests from the New England States Committee on Electricity (NESCOE) for broad changes to the asset condition project process. (See States Press New England TOs on Asset Condition Projects.)
Asset condition projects target existing transmission infrastructure that is aging, defunct or otherwise in need of repair. Costs for asset condition projects in New England have ballooned in recent years and now make up the majority of new transmission spending in the region.
The proposed database would provide ISO-NE and the public with information on age, number of structures, inspection timing, and structure material and construction type for pool transmission facility (PTF) lines. The database also would provide new information on transformers, including operating voltages, age, and testing and inspection information.
The TOs’ presentation noted that future additions to the database could include metrics on asset health, more granular data on the age of structures and information on other PTF infrastructure, including control houses, circuit breakers and relays.
“We wanted to provide something that is impactful by the end of the year, and we will look into providing information on some of these additional elements at a later time,” said Eversource Energy’s Robin Lafayette, also representing TOs Avangrid, National Grid, Rhode Island Energy, VELCO and Versant Power.
Lafayette added that developing the asset health metric will take some time and that the TOs will need to be sensitive regarding confidential infrastructure information.
In a July letter to the TOs, NESCOE wrote that the “database should provide a comprehensive view of all information necessary to guide and inform holistic asset condition prioritization and decision-making.”
Beyond the database, NESCOE also recommended the TOs develop asset condition project spending plans, standardize the stakeholder review process and develop a criteria-based approach for asset condition solutions.
“The pace and scale of recent asset condition projects demonstrate the time urgency of such reforms,” NESCOE wrote. “By taking time now to slow down and establish a transparent and predictable asset condition process, New England can move toward work on a right-sizing approach — an important part of holistic planning that will allow for efficient transmission investment at the pace and scale needed for the region’s clean energy future.”
Dominion Energy on Monday asked Virginia’s State Corporation Commission (SCC) to approve a long-duration energy storage pilot project that it said would greatly increase the amount of time batteries can discharge power to the grid.
The utility wants to install two storage facilities at its Darbytown Power Station, a natural gas plant in Richmond. One will test zinc-hybrid batteries from Eos Energy Enterprises, and the other will test iron-air batteries developed by Form Energy that can discharge for up to 100 hours, compared to the average of just four hours for most standard lithium batteries on the market.
“We are making the grid increasingly clean in Virginia with historic investments in offshore wind and solar,” Dominion Energy Virginia President Ed Baine said in a statement. “With longer-duration batteries in the mix, this project could be a transformational step forward, helping us safely discharge stored energy when it is needed most by our customers.”
The SCC needs to approve the project, as does Henrico County. If approved on time, construction would start by late next year, and the two battery systems would be operational by late 2026.
Virginia’s Grid Transformation and Security Act of 2018 directed the development of battery storage pilot programs. Dominion has built three already in other parts of the state and has another three under development.
The proposal comes as Dominion is working to develop the largest offshore wind project in the country and continues to expand the second-largest fleet of solar panels in the country.
The batteries are meant to help improve the integration of renewable resources and cut the need for additional generation during times of high demand. Dominion also is seeking approval of two other battery projects; if the SCC authorizes them all, it will have 28.34 MW of batteries on its system, compared to 16 MW now.
Dominion evaluated proposals from more than 30 companies and picked Eos and Form because they have paths to commercial viability, as well as safety, the supply chain, efficiency and support from investors, it told the SCC.
Form’s iron-air battery is a 4.94-MW/494-MWh AC multiday system, while Eos’ zinc-hybrid is 4 MW/16 MWh.
“These technologies are expected to have lower thermal runaway risks than lithium-ion energy storage currently presents,” Dominion said in its application. “Additionally, recent history has shown significant pricing volatility and supply chain constraints for lithium-ion battery materials that could cause limits to the energy storage buildout plans.”
Competition for the raw materials for lithium-ion batteries with the vehicle market is getting increasingly fierce, which will significantly increase price volatility. The grid also is going to need long-duration energy storage to help balance the growing share of intermittent resources, Dominion said.
The Form system is made up of 128, 37-foot containers, while Eos’ is made up of 39, 17-foot containers. The two facilities also will require about 10 inverters and two transformers. Despite covering a total of 435,600 square feet, Dominion said the project will be largely hidden from neighbors on the existing plant’s site, so it does not present any environmental justice issues.
Form’s battery is made of iron, water and air. It works by using “reversible rusting.” While discharging, it takes in oxygen from the air and converts metal iron to rust, and while charging, the application of an electrical current converts the rust back to iron, and oxygen is released.
“We are pleased to partner with Dominion Energy on the innovative Darbytown Storage Pilot Project and look forward to delivering a 100-hour iron-air battery system that will enhance grid reliability and provide Dominion’s Virginia customers with access to wind and solar energy when and where it is needed over periods of multiple days,” Form CEO Mateo Jaramillo said.
Eos’ system can operate in three- to 12-hour discharge configurations. During charge and discharge, ions move through electrolytes to their respective electrodes to donate or accept electrons, creating a current flow through the battery’s bipolar stack.
“We are proud to have been selected for this critical project. Dominion understands that meeting our future energy needs requires multiple storage technologies,” Eos CEO Joe Mastrangelo said. “We’re excited to show Dominion how well our zinc-hybrid batteries perform.”
Dominion is asking to spend about $70.6 million on the project. That works out to $7,897/kW, which is a premium compared to the $1,325/kW standard batteries cost, according to U.S. Energy Information Administration data used in its 2022 Annual Energy Outlook, the agency’s most recent.
The Texas Public Utility Commission’s executive director last week praised the efforts of the state’s regulatory agencies to push utilities to weatherize their facilities following the disastrous 2021 winter storm.
Speaking during the Texas Reliability Entity’s annual winter weatherization workshop, the PUC’s Thomas Gleeson said both the PUC and the Texas Railroad Commission (RRC), which regulates the intrastate natural gas and oil industry, have approved orders that have strengthened the electric grid and gas infrastructure against extreme weather.
“If you look at the acute onset issues that happened during Winter Storm Uri and also what you saw some of during Winter Storm Elliott, those mitigation tactics have worked,” Gleeson said during the Sept. 13 workshop. “We’ve performed better, and I think we can all agree that as we continue to learn more, we’ll continue to iterate all those rules to ensure that the grid remains reliable and resilient and progresses even further.”
The two commissions have added winter and summer weather preparedness standards for the utilities they regulate and have followed up with inspections to ensure compliance. ERCOT has inspected more than 1,100 generation resources and transmission facilities before the past two winters. Gleeson said only four inspected sites were forced offline or derated during Elliott.
Inspections for summer preparedness began in June. Gleeson said about 500 inspections of generation and transmission sites will be conducted and a final report issued in October.
Mysti Doshier, the RRC’s assistant director of critical infrastructure, said a “majority” of operators have achieved compliance at more than 99% of facilities when they were inspected. More than 99% of violations were resolved within 30 days.
A 28-year veteran with the RRC, Doshier said the department had four employees when she joined in 2020. It now has 99, two-thirds of whom are inspectors.
“Just like with you guys, whenever you’re talking about the amount of critical facilities or critical components that you had to identify,” she said, addressing her audience, “that’s the same thing with us. We go out to an oil lease and there’s 100 wells. … the critical components that we actually inspected were probably upwards of 30,000. We’ve got a great group of folks. These folks took on the challenge and they’ve done a really fantastic job.”
“There’s always something to be learned about how we operate in extreme conditions,” the Texas RE’s chief engineer, Mark Henry, said. “We saw, not unexpectedly, a number of unit issues much, much lower than what we saw in Uri, which is testament to the effectiveness of the actions that have been taken since … Uri.”
Henry said NERC’s recently revised guidelines for generation units’ winter readiness include a collection of recommended industry practices. Incorporating those practices is strictly voluntary, he said.
The PUC has added a rule this year for additional emergency preparation measures “reasonably expected to ensure sustained operation” at the 95th percentile minimum average 72-hour wind chill value, effective Dec. 1. That rule is stronger than NERC’s draft reliability standard (EOP-012-1) that requires generators with a commercial operation date after the standard’s effective date to use freeze-protection measures capable of the unit’s continuous operation for at least 12 hours.
New York agencies revealed updated modeling Tuesday indicating the state in 2050 could have a roughly 2 GW higher peak load but 4 TWh lower annual load than previously predicted (20-E-0197).
The Energy Policy Planning Advisory Council, which represents every energy sector and acts as an advisory board to the Public Service Commission, held its first stakeholder meeting to discuss the Joint Utilities’ updated Coordinated Grid Planning Process and begin to implement the state’s net-zero Climate Leadership and Community Protection Act.
The CGPP seeks to align New York’s transmission system development with its emissions reduction goals, while attempting to control costs and speed up processes as the state ramps up its energy production and consumption. The PSC kicked off this two-year, six-stage planning process after approving the CGPP in August. (See NY Creates Coordinated Grid Planning Process.)
While the PSC will finalize the CGPP’s framework, the EPPAC plays a key role in shaping the direction of the state’s grid planning by providing recommendations.
The Department of Public Service and the New York State Energy Research and Development Authority staff presented updated results from the integration analysis, showing 2050 peak load would increase roughly 55% and annual load increase 90% over 2020 levels.
NYSERDA’s IA is an economywide assessment supporting CLCPA implementation by modeling proposed emissions reduction and mitigation strategies and since has been modified to include updated reports from the Department of Environmental Conservation, as well as new sensitivity assumptions.
The updated outcomes show no significant impact on key topline cost and benefit metrics, but they do show some notable differences in predicted outcomes, including that New York’s economywide electrification is driving higher peak loads but that these are offset by efforts to decarbonize the building and transportation sectors.
These offsets are seen in the modeling through greater representation of building heating upgrades, increased electric vehicle infrastructure and better accounting of the effective load carrying capacity provided by certain renewables.
The IA has modeled only Scenario 2 of NYISO’s System and Resource Outlook, but staff emphasized this work is ongoing and they would return with more results from other modeled scenarios to help bound their assessments.
The CGPP has six stages, and the EPPAC is aligning multiple scenario forecasts and climate policy objectives, with the assumptions necessary to effectively develop its predictive modeling.
Elizabeth Grisaru of the DPS noted that the EPPAC operates on a tight timetable, with final CGPP recommendations due to the PSC for review July 1, 2025.
Therefore, the EPPAC is poised to meet twice a month with stakeholders to continue discussions.
Q&A
Stakeholders at the meeting had questions about both the updated CGPP modeling and staff’s presentation.
A common theme centered on how resources like hydrogen, dispatchable emission-free resources and energy storage were treated in the CGPP’s modeling and whether assumptions for these technologies were CLCPA-compliant.
Raya Salter, executive director of Energy Justice Law and Policy Center, said she worried staff were getting ahead of the PSC in determining “what should and shouldn’t be considered zero emissions” and wondered if the modeled level of hydrogen penetration is consistent with the CLCPA. The PSC is debating what resources can assist the state in achieving its net-zero goals. (See Contentious Commentary on Zero-Emissions Path in NY.)
The IA models hydrogen as green hydrogen, meaning produced cleanly through electrolysis, but some attendees said they worried about whether the role of hydrogen was being overvalued in the modeling, in lieu of other renewables.
Nick Patane, senior project manager at NYSERDA, responded to this and similar hydrogen questions by clarifying that the model assumes 50% of hydrogen production occurs in-state and the other half is imported. He added that the IA models hydrogen as green hydrogen, meaning it is produced only cleanly through electrolysis.
Erin Hogan of the state’s Utility Intervention Unit and William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, had questions about DEFRs, and its related technologies, and whether these resources are being modeled correctly.
Hogan asked whether the IA accurately predicts the expected lifetime of certain intermittents, such as batteries, and if they are modeled in the state’s future transmission system according to their expected lifetime. “We need to find a Goldilocks solution: We don’t want to build too much, but we don’t want to build too little, and we want to build it in the right place,” she said.
Following this theme of nuanced transmission planning, Acker noted it’s critical to accurately model DEFRs, since certain classes of these resources have different effects on the transmission and distribution system that must be accounted for when deciding where to install new resources or make system upgrades.
Kevin Steinberger, director of E3, which developed the modeling, responded that its model was built to be flexible to account for those resources, but added that his team has been comparing notes with NYISO to ensure compatibility.
Other stakeholders asked about the CGPP’s modeling itself: how it was built, what its long-term implications for the state’s climate goals are and whether more inputs would be added.
Hogan asked about the continuation of transmission costs and benefits beyond the model’s study period.
Jason Frasier, senior manager of transmission planning at NYISO, responded that the ISO’s Outlook, which is where the CGPP’s modeling scenarios are pulled from, does not explicitly model beyond its study period but does have a perpetual setting that assumes the metrics from the final year are carried onward.
Hogan and others also asked if more scenarios would be added to IA, which staff confirmed was the case and that two more scenarios would be included in the CGPP’s modeling, as well as other market sensitivities.
One final concern expressed throughout the discussion was the need for transparency and stakeholder collaboration.
Stakeholders sought to ensure they would be contributing meaningfully to the final CGPP product, and staff promised to ensure transparency where possible, though they did cite some instances where issues related to confidentiality may make this difficult, particularly as it relates to generator retirements.
Staff added that a dedicated EPPAC website would be created to make locating relevant materials easier.
Treasury is using the principles to support mobilization of private-sector capital to address the effects of climate change and accelerate the green energy transition.
The agency said government plays a role in accelerating the transition, but the private sector will need to provide increasing amounts of capital and expertise to make it happen.
The nine principles center on Scope 3 greenhouse gas emissions — those indirectly included in a company’s value chain, typically the largest type of emissions for financial institutions.
The first principle reads:
“A financial institution’s net-zero commitment is a declaration of intent to work toward the reduction of greenhouse gas emissions. Treasury recommends that commitments be in line with limiting the increase in the global average temperature to 1.5°C. To be credible, this declaration should be accompanied or followed by the development and execution of a net-zero transition plan.”
The other eight principles drill down on ways to carry out these commitments, from transparency to environmental justice to credible metrics and targets.
Treasury Secretary Janet Yellen expanded on this point later Tuesday in remarks to the Bloomberg Transition Finance Action Forum in New York City.
“There is extensive evidence showing that the changing climate has significant financial impacts,” she said. “Without considering these factors, financial institutions risk being left behind with stranded assets, outdated business models and missed opportunities to invest in the growing clean energy economy.”
Counterpoint
As Treasury published its guidance Tuesday, Climate Impact Partners published a less-rosy picture of progress.
In its fifth annual report on the subject, the carbon reduction market company found that not one of the Fortune Global 500 Companies increased its 2030 climate commitments last year.
Only 3% added 2050 commitments and 34% remain without climate commitments of any kind, the study reported.
There were some bright spots: More than 75% of companies now report emissions, and those that do report emissions earned a bit more in 2022 profits than those that do not.
Operational emissions of companies with a target in 2030 or sooner decreased 7% in 2022, compared with a 3% increase for companies without a target.
“The lack of climate commitments from some of the world’s largest companies is concerning as we get closer to 2030,” Climate Impact Partners CEO Sheri Hickok said in announcing the study. “At this critical juncture, we need companies to lean in, not pull away. The good news is that we have found clear markers for the companies making the most positive impact on emissions today, serving as an example for others to follow.”
The companies tracked are the largest 500 companies in the world — realizing $41 trillion in 2022 revenue, employing more than 70 million people and accounting for more than a third of the world’s gross domestic product.
As such, they hold significant influence on suppliers, customers, other businesses and governments, Climate Impact Partners wrote.
As the organization was preparing its report, 22 attorneys general from Republican states were taking steps that could discourage concerted emissions-reduction efforts as potentially illegal.
Tennessee Attorney General Jonathan Skrmetti sent a letter requesting information from signatories to the Net Zero Financial Providers Alliance emissions reduction commitment.
This may violate state and federal laws including antitrust and consumer protection statutes, Skrmetti wrote on Sept. 13.
Although many signatories are direct competitors, “they nevertheless commit to using their market influence to enforce their collective climate agenda in the broader economy and to ‘[w]ork in coordination’ with other UN-convened ‘Net Zero’ groups. Further, these pressure tactics are backed up by substantial market power,” he wrote.
A disclaimer included in the NZFPA commitment — “The parties making this Commitment do so subject to any legal, regulatory, professional standards and professional or ethical obligations that apply to them” — does not alleviate the concerns of the attorneys general, Skrmetti wrote.
Also signing his letter were the top legal officials of Alabama, Alaska, Arkansas, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, New Hampshire, Ohio, Oklahoma, South Carolina, Utah, Virginia, West Virginia and Wyoming.
MISO announced it’s pushing back a scheduled meeting to discuss three new substations proposed by Entergy for expedited treatment in the RTO’s annual planning cycle.
The grid operator said it needs the pause to conduct more analysis on the trio of expedited projects to serve new load interconnections near Jackson, Miss., before it can recommend the projects move ahead.
Entergy proposed three new substations for the fast-growing industrial area of Madison County in August. It sought MISO go-ahead to build two new 230-kV substations to serve 267 MW in load apiece and a 500/230-kV substation to cover 537 MW in new load.
Entergy wants to bring the 230-kV substations online by early 2025 and 2026. The utility envisions the 500/230-kV substation to be operational by mid-2027.
But MISO said the “size and complexity” of the new projects means it was forced to postpone its Sept. 22 South Technical Study Task Force meeting, where it was due to discuss study results with stakeholders. MISO studies expedited project requests for adverse impacts on its system.
MISO said its review uncovered transmission issues were the proposed substations to be built. The RTO said its expansion planning team now must work with affected transmission owners to resolve the issues and said it will schedule a new task force meeting once it can complete its review.
MISO has been fielding numerous and more complex out-of-cycle requests for projects that can’t wait to begin construction until the early December approval typically reserved for the MISO Transmission Expansion Plans (MTEPs).
The U.S. is behind Europe in deploying HVDC transmission technology, according to a report released Tuesday by the Brattle Group and DNV for clean energy and transmission advocates.
“The Operational and Market Benefits of HVDC to System Operations” noted that 300 GW of HVDC capacity has been installed worldwide, with an additional 150 GW in the planning stages, most of it in the last decade. The report was sponsored by the American Council on Renewable Energy, Allete, Clean Grid Alliance, GridLab, Grid United and Pattern Energy Group.
“HVDC transmission has evolved dramatically over the last five to 10 years,” Brattle Group Principal and co-author Johannes Pfeifenberger said on a webinar hosted by ACORE. “HVDC offers higher capacity, longer distance [and] lower loss transmission on a smaller footprint, which really are key advantages.”
Connecting HVDC lines to the standard AC grid requires converters, and the newer voltage-sourced converters, which can be switched on and off by an external control signal — unlike the historically more common line-communicated converters that can only be turned on by an external signal — greatly enhance HVDC’s capabilities, Pfeifenberger said.
Europe has led the way in deploying modern HVDC technology with VSC converters recently, with about 50 GW of projects in operations and another 130 GW planned over the next 10 years. North America accounts for only 3% of the technology’s use and 30% of planned projects, most of which have been proposed by merchant developers.
“It’s pretty straightforward if you want to move power over long distance: DC is a much more efficient way to do that in terms of right-of-way cost and controllability,” said Grid United CEO Michael Skelly, whose firm has proposed a number of HVDC projects to connect the three interconnections.
In the mid-2000s, when Texas was considering the Competitive Renewable Energy Zone lines to bring wind power to market, they considered HVDC; Skelly said now there might be a “little bit of buyer’s remorse.” With how much growth ERCOT has seen in recent years, HVDC might make a comeback, he added.
The one domestic market the report highlighted as fully embracing HVDC technology is CAISO, with Pfeifenberger noting that the Trans Bay Cable in the San Francisco area is the first VSC HVDC project in the world.
“Because they were the first operator of a VSC-based HVDC line, the Trans Bay Cable, they really like the technology; they have optimized it into the market; they’re fully co-optimizing controllable transmission with generation in the day-ahead in real-time markets,” Pfeifenberger said. “They’re optimizing transmission across the entire West now. And they are developing a specific way to integrate merchant transmission lines into all this market optimization.”
The report is full of anecdotes about European countries starting to knit their grids together with new HVDC lines. Germany is linking up its wind-rich north and solar-rich south with major projects. Italy, which has HVDC subsea cables connecting Sicily and other islands, is now expanding its use similarly to its northern neighbor. Other examples abound around the continent.
HVDC works better than AC lines when it comes to burying transmission, said DNV Vice President and report co-author Cornelis Plet.
“Whenever power needs to be transported over more than 50 miles by underground cable or maybe 300 to 400 miles per overhead line, HVDC is the only technical, feasible option,” Plet said.
In addition to the ability to be out of sight, HVDC technology also requires a smaller footprint so it can help get transmission built in urban areas where new rights of way are very hard to procure, he added.
Another reason Europe has been building out so many lines is the growth of offshore wind, as DC lines can operate underwater. Now a major question on the continent is whether the HVDC lines should operate as single entities or be stitched together in an HVDC grid that overlays the AC system, Plet said.
One issue with the rapid growth in Europe is supply-chain concerns, as the manufacturing base — while currently sufficient — would be strained to try to meet an uptick in demand from North America as well, he added.
“The U.S. must build a similar project pipeline and, importantly, take advantage of the significant planning and operational experience that has already been gained with modern HVDC systems,” Plet said.
Another hurdle to getting HVDC or other major transmission needed to expand renewable power and address climate change is the current permitting process, said Rep. Sean Casten (D-Ill.), Congress’ chief FERC booster.
The lack of transmission is one of the two main problems with renewables, the other being that it “is too damn cheap,” Casten said on the webinar.
“You’ve generated this problematic resource that is super cheap: Whether it’s wind, whether it’s solar, you have effectively zero marginal cost,” Casten said. “And on the other end of that wire, you have a person or an entity — maybe it’s an RTO, maybe it’s a utility — who has an entire pile of assets that are dependent on earning $50, $60, $70/MWh, and you want to put $30 power into that market.”
That gives the entities who would receive that cheaper power a clear economic disincentive to do so, he added. The politics of defending high prices are not good, so opponents come up with spurious arguments like transmission causes “eagle cancer,” Casten quipped.
Casten and Rep. Mike Levin (D-Calif.) are working on a bill that seeks to be the Democrats’ opening position on transmission permitting. The two are trying to make sure the industry’s profit motive is aligned with transmission expansion to bring renewables to market, get the right participants in the planning process and then smooth out the siting and permitting processes.
“Let’s not make it harder to permit a transmission line than it is to permit a natural gas pipeline, which it is as long as we have only one authority responsible for one of those,” Casten said.
