FERC Commissioner David Rosner hopes that the rehearing order on Order 1920 will win broader support than the 2-1 split vote that produced the original.
Speaking at the WIRES Fall Member Meeting, Rosner said that based on the comments in the docket and discussion with his colleagues, many stakeholders agree on some modest changes to the original that are still in line with its intent to expand the transmission grid.
“I’m really hopeful that we can get five votes on a rehearing order, but I don’t know, we’ll see what happens,” Rosner said. “I mean, all I can really guarantee is one vote, but I’m committed to work through that.”
One area Order 1920 did not address much was interregional transmission, Rosner said, adding that he would be happy to implement anything Congress manages to pass. Expanded authority over interregional transmission is part of the Energy Permitting Reform Act that cleared the Senate Energy and Natural Resources Committee this summer and could move forward in a lame duck session after the election. (See Manchin-Barrasso Permitting Bill Easily Clears Committee.)
NERC CEO Jim Robb’s argument at the recent FERC reliability technical conference that interregional transmission can help the grid deal with emerging issues resonated with Rosner, he said. (See FERC Grills Grid Stakeholders on Reliability.)
“I think interregional is really important,” Rosner added. “I also don’t have any updates on commission action on that, but I will leave it at, I think it’s really important. … We have a good record open already on this, and we have lots to think about.”
Supply Chain’s Impact on the Grid
While FERC has plenty of work to do on its own to ensure grid reliability, some issues largely fall outside of its purview, which includes supply chain disruptions, such as during the COVID-19 pandemic, noted Hailey Siple, director of national security policy for the Edison Electric Institute.
The first weeks of the pandemic were some of the busiest of Siple’s career, she said, as she had to work to help manage the industry’s response.
“While we were doing that, that is the first time that I remember really sitting down and thinking about supply chain, the energy supply chain in particular, as a national security threat,” Siple said. “And I think the conversation changed very much at that point. So, we had really no immediate impacts those first couple weeks or months, but a few months down the road, we had first one of our chief procurement officers come and say, ‘Hey, we’re seeing some long lead times.’”
EEI started to hear from more and more of the industry that the pandemic was stretching supply lines thin, so it started working to help address the issue along with the rest of the industry and the Department of Energy.
“There is a fantastic relationship between industry and not just EEI, but all segments of the industry, and the Department of Energy through the Electricity Subsector Coordinating Council,” Siple said. Once the worries about the supply chain were known, ESCC set up a team to work on the issues, she recalled.
Now DOE itself has set up its Office of Manufacturing and Energy Supply Chains to help coordinate the issue, said its chief strategy officer, Arthur Haubenstock.
“A good chunk of what we are programming is in transmission, because it is the lifeblood of our energy system, and will increasingly be so as we work on industrial decarbonization, which is another area that our office is responsible for,” he added.
The need to get energy supply chains right will also be important to deal with the strains being placed on the grid, whether it is from climate change or increased demand, Haubenstock said.
Increased demand from data centers, and the utilities looking to plug them into the grid, has been a huge change for Siemens Energy, one of the main suppliers of electric transmission infrastructure, said Anthony Zito, the company’s director of sales operations.
Customers are increasingly aware of the strains and trying to book equipment a decade ahead of time for sites that are not even on the drawing board now, Zito said. But with the need for data centers, the equipment will definitely be used.
“We had one data center customer that, four years ago, we were the sole supplier to them globally,” Zito said. “We now can’t serve more than 20% of what they say their need is for the next couple years.”
Demand is so high, some data center developers and utilities have approached Siemens to buy out all its capacity for the next five or 10 years, he added. The firm has declined such offers because of the risk that a single customer’s business plans could change.
“What happens if they go bankrupt, or they decide they’re not building anymore, and now you’ve alienated every other customer, every other utility, data center customer, renewable customer?” Zito said. “So, we look at sort of a mitigation strategy to spread the love around.”
FERC has approved a settlement between Entergy and SERC Reliability carrying a $141,000 penalty for violating NERC reliability standards, the commission said this week.
NERC filed the settlement with the commission Sept. 30 in its monthly spreadsheet notice of penalty (NP24-13). It was the only settlement the ERO filed publicly for the month, though NERC also filed a separate, nonpublic spreadsheet NOP involving violations of the Critical Infrastructure Protection standards. Information on CIP violations is not typically disclosed to the public for security reasons.
FERC said in an Oct. 30 filing that it would not further review the agreement, leaving the penalty intact.
Entergy’s settlement with SERC stemmed from a violation of PRC-005-6 (Protection system, automatic reclosing and sudden pressure relaying maintenance). The utility self-reported the infringement to the regional entity June 2, 2022.
While performing scheduled relay maintenance at the Hot Springs substation in Arkansas, Entergy workers discovered that scheduled maintenance and testing activities had not been performed on four panels at the substation. An investigation determined the panels had been “inadvertently suspended in the substation work management system (SWMS)” during the installation of a new high-voltage line relay panel.
The scheduled maintenance and testing had last been performed in 2013 and should have been repeated no later than Dec. 31, 2019. After Entergy discovered the oversight, it completed the testing April 9, 2022.
Following the detection of this infringement, Entergy performed an extent of condition review and in February 2023 found 208 additional relay panels that had been suspended under similar circumstances to the Hot Springs panels. Of these, two panels at the Mabelvale substation still were suspended in the SWMS and were five years overdue for scheduled maintenance and testing, despite remaining in service. The utility performed the required service by April 13, 2023.
In a third instance, Entergy was reviewing a list of potentially overdue work in September 2022 and found that “it failed to complete an … impedance test” on a battery at the Pintail 138-kV substation that should have been done by the previous month. The utility had scheduled the test for March 2022, but rescheduled it several times; by the time it completed the test Sept. 13, 2022, it had exceeded NERC’s mandate of 18 months between tests.
Entergy’s final instance of noncompliance was discovered in August 2023, when the utility’s area planner realized required maintenance on two panels at the Independence substation was past due. Upon review, the utility determined the panels had been mistakenly designated as “N/A” (not applicable) in regard to PRC-005-6. An additional incorrectly designated panel was found at the Little Rock Gaines substation. Maintenance and testing at both substations’ overdue panels were completed by Dec. 14, 2023.
SERC identified the causes of the violation as “ineffective communication, ineffective internal controls, deficient process [and] procedure, and ineffective training program.” The RE said the noncompliance constituted a “moderate risk” to grid stability, noting that the failure to complete required maintenance and testing activities “could result in protective system failures and misoperations impacting a [large] portion of the transmission system.”
Entergy’s mitigation plans included completing the missing maintenance and testing at all affected panels, developing a SERC critical functions checklist for planners and schedulers, updating the work management process for transmission lines and substations, and establishing metrics to show “how many SERC tasks have gone past the Entergy target date.” SERC noted that the utility reported mitigation activities were completed July 25, 2024, although the RE had not yet verified completion at the time of filing.
When determining the penalty, SERC “considered Entergy’s PRC-005 compliance history to be an aggravating factor.” The RE observed that Entergy has five prior relevant instances of noncompliance, four of which involved similar causes and mitigations that SERC suggested could have helped prevent the most recent instances. Mitigating credit was applied for Entergy’s cooperation throughout the investigation, its self-reporting of the violations in a timely manner, its acceptance of responsibility and its agreement to settle the matter.
ATLANTIC CITY, N.J. — The Bureau of Ocean Energy Management has decreased its offshore wind permitting times 20% as it gains experience and works to expedite development of the clean energy sector.
BOEM Director Elizabeth Klein shared the news as she joined other federal regulators and a manager at a leading offshore wind developer for a discussion on lessons learned from early U.S. offshore wind projects.
There has been a lot to learn, certainly, as well as ample opportunity to learn from setbacks as the industry tries to gain traction in the United States.
“We’ve examined our permitting processes because we want to make sure that we are being as efficient as possible while also creating durable decisions,” she said Oct. 29 at Offshore WINDPOWER 2024.
The most recent of these updates were announced the same day Klein spoke: BOEM debuted its new POWERON acoustic monitoring program to protect biodiversity in offshore wind lease areas, and it signed a memorandum with the Department of Defense to collaborate on their reviews of development proposals.
“There is just an incredible amount of effort, there’s an incredible amount of work that I think we can all be very proud of,” she said.
The Biden administration this year rebranded the Federal Permitting Improvement Steering Council as the Permitting Council. Executive Director Eric Beightel said it has sought to improve communication and understanding across the many federal agencies involved in offshore wind permitting and avert potential conflicts among a diverse set of core missions.
“I think that that is a very powerful tool that is underutilized in government, and that we’re anxious to do more of it,” he said. “At the end of the day, the goal for me is to work ourselves out of a job — that we’ve instituted these sorts of best practices, these open lines of communication in such a way that it just becomes more normal.”
Janet Coit, assistant administrator for NOAA Fisheries, said her agency has been involved in marine mammal protection work for all 10 of the federally authorized offshore wind projects to date.
“Many of the folks who work at NOAA Fisheries were an office of one or two people, and we’ve also — as well as the industry — had to staff up, had to look for ways of providing more specific and clear guidance, and learned a lot along the way,” she said.
Protection of marine mammals, especially whales, is a key target for offshore wind foes, so it is critical to produce science-based decisions that will withstand litigation, Coit said.
The most prolific U.S. offshore wind developer, Ørsted, has encountered many teaching moments as it put steel in the water.
“Spoiler alert: Things don’t always go as planned when you hit the field, when you hit the water,” said Patty DiOrio, who leads the Danish company’s North American offshore project development team. “So I’ll be talking about some lessons learned. … We’re getting better and better with every position that we install.”
Some highlights from the four speakers:
Little things like making sure agencies are talking to the right people at other agencies sound simple but do not always happen. — Klein
Making the Notice of Intent checklist and FAST-41 processes work in concert is important, and getting the Permitting Council involved in the process early makes it more effective. — Beightel
Having a large enough staff and budget is critical. — Klein
Clarity, predictability and consistency by regulators are all good, but flexibility is critical, because weather, supply chain hiccups and other factors can change the best-laid plans. — DiOrio
Good communication allows problems to be addressed early, before they fester. — Beightel
Timely onshore grid upgrades are a priority, because they represent an unknown cost factor for developers. — DiOrio
Mitigation of effects on fisheries should be thought out regionally rather than project by project. — Coit
The Permitting Council is investing millions in artificial intelligence technology to speed administrative review of comments and documents so staff can concentrate on the necessary analytic work. — Beightel
NOAA Fisheries is hiring people to meet a recommendation by developers to have dedicated project coordinators. — Coit
DiOrio seconded this last point: “You cannot overstate how key they are. They really just keep the gears in motion, and it makes a huge, huge difference.”
Panel moderator Ted Boling, a partner at law firm Perkins Coie, asked DiOrio if she thought the federal government is responsive.
“Do you see your lived experience with installation being reflected in the way federal agencies are approaching mitigation, monitoring, the plan of operation?” he asked.
“I think we’re getting there. I really do. We’ve gotten good collaboration when things happen,” she responded.
Boling lobbed an audience question at Klein: “There is a phrase, ‘Don’t let the perfect be the enemy of the good.’ It can feel like that standard of approval is perfection. Can we move to good enough?”
Klein recalled another regulatory learning curve, when early large-scale solar energy projects were proposed in the United States.
“You know, at the beginning, everything can feel new, and it’s like every single environmental review is really difficult and eventually you get to a point where you can benefit from efficiencies, you can use existing environmental documents.”
But now is not the time to cut corners and risk a setback through opponents’ litigation, she said.
“The hope is always that this will become more routine, and it won’t feel so hard to get every single project review across the finish line, because there will be standardization across the industry in some aspects, and it will feel less difficult.”
Deep decarbonization of the New England grid will pose major challenges related to resource adequacy and market administration, ISO-NE concluded in the final report of its Economic Planning for the Clean Energy Transition (EPCET) study, released Oct. 24.
The RTO emphasized the importance of developing dispatchable zero-carbon resources to ensure reliability during extended periods of low wind and solar generation, and said new mechanisms likely will be needed to support dispatchable resources that run only in extreme scenarios.
ISO-NE previously outlined its key findings at its Planning Advisory Committee in August, when it told stakeholders it plans to consider “future market rule enhancements to support the ongoing reliability and economy of the region’s grid.” (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.)
One of the main issues New England will face as it approaches full decarbonization is increasing variability of both demand and supply, with electrified heating and intermittent renewables both highly impacted by extreme weather events, ISO-NE wrote.
“The magnitude of the annual peak will vary dramatically from one year to the next, depending on how cold or how mild a winter the region sees,” ISO-NE wrote. “As a result, some resources needed to maintain reliability during the harshest conditions may only run once every few years.”
Without significant dispatchable resources, decarbonization will require a significant overbuild of wind, solar and batteries, which would come at a significant cost to consumers and have a large land-use impact, ISO-NE said.
The RTO estimated the region would need to add a staggering 97 GW of renewable capacity by 2050 to meet state goals, equating to an average annual addition of 1,293 MW of offshore wind, 268 MW of onshore wind, 955 MW of solar and 952 MW of batteries.
As the proliferation of renewables eliminates power system emissions from increasing amounts of the year — first in the spring and fall seasons, followed by the summer and eventually the winter — the value of new renewables will decrease, the modeling found.
“Fundamentally, as decarbonization accelerates, but remains highly correlated with the seasons, zero-carbon resource additions will produce surplus energy for increasing periods of time, and their cost per MWh will rise,” ISO-NE said.
The declining value of additional renewables will correspond with the increasing need for dispatchable resources and long-duration storage, ISO-NE said. The RTO found 100-hour batteries — such as those planned for development in Maine — will become particularly valuable as the region approaches 2050.
“However, even with a significant penetration of 100-hour batteries, the later years of this sensitivity still experience stretches of time when 100-hour batteries become depleted and significant fuel-secure dispatchable generation is needed to satisfy demand,” ISO-NE said.
To address these gaps, ISO-NE highlighted low-carbon fuels such as synthetic natural gas (SNG), clean hydrogen and renewable diesel, as well as small modular reactors (SMRs), as potential options.
The RTO specifically modeled SNG, noting that it could make use of the existing gas transmission network, while hydrogen likely would require significant amounts of new storage and transportation infrastructure.
It found that including 19,637 MW of SNG resources “achieves the states’ 2050 decarbonization targets while requiring 37% less new renewable capacity,” with high SNG fuel costs offset by the diminished need to overbuild renewables.
ISO-NE also modeled the effects of including SMRs, finding that “a renewable-dominant build-out that also includes 15.1 GW of SMRs achieves the states’ 2050 decarbonization targets while requiring 57% less new renewable capacity.”
The RTO emphasized that cost projections for SMRs remain highly uncertain, but estimated the inclusion of SMRs could reduce overall capital costs by 33% relative to the base case, and said the SMR case still outperformed the base case when the model doubled the SMR cost assumption.
Projected tons of carbon per day | ISO-NE
The report did not include a focus on how increased interregional transmission could affect the system. Multiple studies have found increased transmission between Québec and New England to reduce the cost of deep decarbonization in the Northeast by enabling Québec’s hydroelectric resources to balance out intermittent renewables. (See Québec, New England See Shifting Role for Canadian Hydropower.)
Massachusetts Institute of Technology researchers have found that increased bi-directional transmission between the U.S. and Canada would cut overall decarbonization costs by reducing the need to overbuild renewables. The researchers estimated that 4,000 MW of additional transmission between New England and Québec would reduce the overall costs of full decarbonization by 17-28%.
ISO-NE also noted that increased demand flexibility, which has been a top priority for consumer and climate advocates in the region, likely would not provide significant benefits during extended winter periods of low wind generation.
“While EV charging or heating could be delayed by a few hours, heating in particular cannot be delayed for longer time periods,” ISO-NE wrote.
Minimum Load Concerns
The RTO also noted the proliferation of behind-the-meter solar could create minimum-load issues for resources that are not able to quickly ramp down their production.
“All weather years in the modeled 2032 system experience days in which the net load falls below this threshold,” ISO-NE found.
It noted that flexible load — such as demand from electric vehicle charging — could be incentivized to alleviate these issues, or the region could increase its exports if other regions are not facing similar conditions.
Market Challenges
Beyond the technical challenges of developing adequate dispatchable zero-carbon resources to support system reliability, significant changes to the current market structures likely will be needed to support these resources, ISO-NE said.
While the energy market currently is ISO-NE’s largest market “by a large margin,” RTO projects overall revenue from the capacity market and from state power purchase agreements (PPAs) to surpass the energy market by 2035. Meanwhile, the proliferation of resources with PPAs — which often still can profit when bidding negative prices into the energy market — could threaten the viability of baseload resources that lack PPAs.
“Baseload nuclear resources are at particular risk of exposure to periods of negative [locational marginal prices], since they cannot increase or decrease their output quickly,” ISO-NE said.
Meanwhile, dispatchable resources needed to ensure reliability may not be used at all within a given year, putting more pressure on the capacity market to provide them with the necessary revenue. ISO-NE officials previously expressed apprehension about relying too heavily on the capacity market, which frequently is subject to intense stakeholder debates.
“Current market rules and other revenue structures may not scale well in a renewable-heavy grid, and the ISO is exploring alternate market structures within its jurisdiction,” ISO-NE wrote.
ISO-NE CEO Gordon van Welie has frequently expressed his support for developing a price on carbon within the wholesale markets but has said this would require full support from all six New England states. The EPCET study noted that zero-carbon dispatchable resources likely would need a price on carbon, or some other incentive, to compete economically with fossil alternatives.
ATLANTIC CITY, N.J. — The 2024 edition of the American Clean Power Association’s WINDPOWER conference was a celebration of achievement by the U.S. offshore wind industry and a recognition of the hurdles it still must cross.
While the regulatory regime facing offshore wind continues to streamline itself, and while the number of turbines in U.S. waters grows almost weekly, important financial and technical challenges remain.
There is also the small matter of the presidential election. Speakers at the microphone Oct. 29 seldom spoke the name “Trump,” but the possibility of the avowed wind turbine hater returning to power clearly was on the minds of the crowd at the Atlantic City Convention Center.
All 10 of the federally approved offshore wind farm plans in U.S. waters have been greenlighted by federal regulators after Trump left office in 2021. He has made various threats and promises to take counteraction as soon as Day 1 of a second term.
American Clean Power CEO Jason Grumet said there is no way to go but forward. He recounted the progress the industry has made even amid the global macroeconomic challenges of the past two years and framed it against the growing demand for electricity.
“If we don’t actually have the power coming from renewable sources like offshore wind, the country’s going to have a choice. When we have a choice between clean power and polluting power, we choose clean power,” he said.
Imagine, Grumet said, the community opposition that would emerge to keeping coal-fired plants online and building a network of natural gas pipelines to power new gas plants.
The push to continue the progress offshore is necessary, he said, but not necessarily easy.
Attendees at the conference were greeted as they arrived by a handful of the offshore wind foes who live along the New Jersey coast.
“It’s hard work and it’s courage. Not easy to try something new, to have careers and communities and tens of billions of dollars resting on your ability to accomplish great things,” Grumet said.
A recurring theme at the conference was winning hearts and minds to build support for offshore wind. A path to this, many speakers said, is demonstrated benefit. One of the driving factors behind offshore wind construction is benefiting the planet, but a key driver for some people is tangible benefits, generally financial.
Sean McGarvey, president of North America’s Building Trades Unions, said his membership initially was skeptical of clean energy jobs, given that many of the members worked in fossil industries and given the low wages and dearth of labor standards in green economy jobs.
“Not that we were climate change deniers, but we were economic [realists],” he said. Unions were looking for a horizontal transition to clean energy, he said, and through the Biden administration’s policies and signature initiatives such as the Inflation Reduction Act, they got it.
“So the fear factor is taken out of losing jobs in old industries.”
Grumet, whose association represents more than 800 companies in the clean power sector, asked: “How are we doing?”
“Nobody bats 100%,” McGarvey replied, “but for most people in the industry, they’re willing to engage, have a conversation.”
He added that organized labor is a value-added proposition — its 1,600 U.S. training centers and 268,000 apprentices can play a key role in growing the skilled workforce that Grumet and many others in the clean energy sector say is greatly undersized.
“There’s only one institution in the world that trains more people in hard skill sets than we do, and that’s the United States military,” McGarvey said.
“Since we are in a rather dynamic moment in our political history,” Grumet said, “how do you think about the policy imperatives for the next four years?”
“Everything depends on next Tuesday,” McGarvey said. A Harris win would be good news for the offshore wind industry, he explained; a Trump win would not.
He said he first encountered Trump in Atlantic City of all places, back in the 1980s when helping build part of the casino company that helped shape the future president’s image.
“You know, there are certain things that are stuck in his brain, and one of them is he really doesn’t like wind,” McGarvey said.
Grumet sat down with Alicia Barton and Joris Veldhoven, CEOs respectively of Vineyard Offshore and Atlantic Shores Offshore Wind and asked for their take on the state of the industry.
Barton pushed back on the tendency to tally failures and challenges. Instead, she pointed to progress made amid those headwinds: 10 projects have been approved, five have started construction and one is complete.
“This is an industry that’s at a size and scale that is very different than we’ve ever been talking about before,” she said, adding, “I’ve been in this conference for a long time.”
Many speakers at WINDPOWER 2024 emphasized the need for continued progress, for tangible results of all this planning and review, something that would demonstrate the value of offshore wind and help it reach self-sustaining scale as a U.S. industry.
Veldhoven was among the first.
“Make sure that we get projects built,” he said. “That is really what this industry needs, that is what states like New Jersey need at the moment, and I think that’s what we also can do. And we need to make sure, collectively as a group of developers, that enough projects mature so we actually get the steel in the water.”
He added: “Those are some of the things that, per se, don’t really change depending on what happens next week, depending on regulatory frameworks — we need to make sure that we keep moving this industry forward.”
This also builds political capital, Barton said.
“Seeing the reality of projects getting constructed is the signal that, I think, important players across the board are looking at,” she said.
Leaders of almost every state on the central and northern Atlantic coast have been critical to the industry gaining its foothold in U.S. waters and growing. Among the strongest supporters has been N.J. Gov. Phil Murphy (D), who welcomed conference attendees to the Garden State and cheered them on.
“The momentum here in Atlantic City is proof that investing in our nation’s clean energy future is not just about protecting the environment, which it is. It is also about pumping new life into our local economies,” Murphy said.
More than 3,000 people work at companies engaged in offshore wind, he said, and the industry is projected to add more than 10,000 new jobs as it grows.
Murphy played up his state’s growing cooperative efforts with New York. The two states have a bit of a friendly rivalry on their offshore wind goals — with New Jersey currently ahead at 11 GW by 2040 — but also recognize the need to join regionally to better expand the ecosystem needed to reach those goals.
“We and New York share the same goal when it comes to offshore wind, and that is establishing our entire region as the epicenter for the offshore wind revolution,” he said. “And even more importantly, the fact is we need each other. Not just New York and New Jersey, but all of us here in this Convention Center. Building out an entirely new industry from whole cloth is no small feat.”
FERC has approved SPP’s waiver request to delay processing its 2024 generator interconnection study cluster as the RTO works to clear a backlog of GI requests that date back to 2018.
The commission said Oct. 30 that the waiver request met its four criteria for approval in that SPP acted in good faith, the request is limited in scope, it remedies a concrete problem, and granting the waiver will not have undesirable effects, such as harm to third parties (ER24-2860).
The waiver allows SPP to defer starting the definitive interconnection system impact study (DISIS) for the 2024 cluster until completing the first planned restudy of the DISIS-2023-001 cluster; extending the close of the 2024 DISIS queue cluster window from Oct. 31 to March 1, 2025; and opening the 2025 DISIS window until April 1, 2026, or the completion of the second decision point for the 2024 DISIS cluster.
The grid operator told FERC that waiving the tariff provisions will enable it to focus its “limited resources” on processing the unprecedented number of interconnection requests already in the queue. It also said the waiver won’t delay executing GI agreements for pending or future clusters and will prevent lower-queued and future interconnection customers from expending time and resources considering study- and interconnection-cost-related information that could become moot due to restudies of higher-queued clusters.
SPP began tackling the backlog in 2022 with the 2018 cluster. The queue contained 1,139 active requests for 221 GW of capacity at the time; it now has 395 active requests for 82 GW of capacity. The RTO has executed 48 new GIAs for 7.75 GW of capacity during the backlog work. (See “SPP Modifies GI Backlog Process,” SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024.)
The Western Area Power Administration said Oct. 30 that its Sierra Nevada (SN) region will pursue “final negotiations” to join CAISO’s Extended Day-Ahead Market (EDAM), notching another — if expected — victory for the ISO in its competition with SPP’s Markets+.
SN already participates in CAISO’s Western Energy Imbalance Market (WEIM) through its membership in the Balancing Authority of Northern California (BANC).
BANC and its largest member, Sacramento Municipal Utility District, were last year among the first entities to announce their intent to pursue membership in the EDAM, after PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.) BANC members Modesto Irrigation District and the cities of Redding and Roseville have since committed to joining the market.
A commitment from SN would clear the way for BANC to sign an EDAM implementation agreement with CAISO, a well-placed source told RTO Insider.
With WAPA’s approval, BANC expects to join the EDAM in the spring of 2027, the BA said in an Oct. 30 press release.
As part of federal power marketing administration (PMA) WAPA, SN sells low-cost power to irrigation districts, joint power agencies, cities and towns, public utility districts and other public entities from hydroelectric dams operated by the Bureau of Reclamation in the Central Valley Project, including Shasta (676 MW), Trinity (359 MW), New Melones (283 MW) and Folsom (199 MW).
“Working closely with the Balancing Authority of Northern California and our Sierra Nevada customers every step of the way, my staff and I look forward to engaging with CAISO through final negotiations to join this promising day-ahead market development,” WAPA Administrator Tracey LeBeau said in a separate release. “Our dedicated staff will continue to solidify our working partnerships with BANC, customers and CAISO and resolve technical implementation details while ensuring the best possible outcomes for our customers and other stakeholders.”
“We have concluded that participation in EDAM provides the best benefit for BANC and its WEIM participants while leveraging the investment we have made, and preserving the benefits we see, in WEIM,” BANC General Manager Jim Shetler said in a statement. “This decision is also consistent with BANC’s position that evolutionary development of markets in the West provides the most long-term durability. BANC looks forward to collaborating with WAPA-SN and our members as we move forward with EDAM implementation.”
Shetler is a member of the West-Wide Governance Pathways Initiative’s Launch Committee, which for the past year has been developing a proposal to establish an independent “regional organization” (RO) to assume governance of CAISO’s WEIM and EDAM. SN’s membership in EDAM could have at least a minor impact on the governance of the proposed RO, given that the most recent Pathways proposal reserves one seat for PMAs on the RO’s Stakeholder Representatives Committee in either the WEIM or EDAM sectors. (See Revised Pathways Proposal Focuses on Sector Issues.)
In addition to marketing generation from the Central Valley Project Dams, SN also controls portions of the 500-kV Pacific Northwest-Pacific Southwest Intertie, which links the Bonneville Power Administration’s territory in Eastern Oregon with Los Angeles, and the 500-kV California-Oregon Transmission Project linking Southern Oregon with California’s Central Valley. Both lines are vital for moving energy back and forth between the Pacific Northwest and California and the Desert Southwest.
Altogether, the agency operates 884 miles of transmission ranging from 69 to 500 kV and 18 substations.
“Integrating WAPA’s Sierra Nevada region along with BANC into EDAM is a crucial step towards realizing the vision of a fully integrated regional market,” said Elliot Mainzer, president and CEO of CAISO. “Uniting resource-diverse utility partners across the West will enhance reliability, affordability and transmission connectivity. We are thrilled to see our valued partners taking these steps to solidify their position in this market at such a pivotal time.”
As the U.S. faces an increasingly “complex and geographically dispersed” threat landscape, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released its first International Strategic Plan aimed at strengthening the agency’s defense against foreign adversaries.
In the new plan, CISA said its aim is to “shape the international environment to reduce risk to critical dependencies and set conditions for success in cooperation, competition and conflict.” To support this aim, the agency laid out three overall goals:
Bolster the resilience of foreign infrastructure on which the U.S. depends.
Strengthen integrated cyber defense.
Unify CISA’s coordination of international activities.
Meeting the first goal will require working with domestic and international partners across a number of sectors spanning critical infrastructure, including pipelines, telecommunications and essential supply chains. CISA noted that U.S. and foreign infrastructure could be targeted by global terrorists and other malicious actors; therefore, the agency said it needs to build stronger relationships with international partners aligned with its interest, along with promoting standards, regulations and policies to advance its objectives.
To strengthen global cyber defenses, CISA said it intends to grow its networks of trusted partners to provide greater visibility into, and respond to, cybersecurity vulnerabilities and threats from malicious actors. The agency will grow these relationships primarily through engagements between its computer security incident response teams (CSIRT) and those of its overseas counterparts. Engaging at the CSIRT level will “enable the exchange of actionable operational information” such as vulnerability alerts, victim notifications and attackers’ tactics.
CISA also intends to “establish an environment where our partners can organically detect threats … and receive and exchange real-time risk reduction actions,” the agency said. It will do this through training and exercises, as well as providing its partners with information-sharing capabilities. Additionally, CISA will work to encourage the development of organic risk reduction capabilities.
The agency’s third goal, unifying coordination of international activities, will require CISA’s Stakeholder Engagement Division to “establish a governance structure to advise on international matters and provide a clear articulation of [CISA’s] international priorities.” In addition, CISA will aim to improve its internal information sharing with the benefit of international lessons learned, and provide its workforce deployed overseas with special training.
CISA said these actions will result in partnerships that can act as a “force multiplier” to enhance the effectiveness of its cybersecurity actions beyond what CISA can provide on its own. The agency said it sees the strategic plan as “a process, not simply a publication,” and it therefore will review progress toward its goals quarterly.
CISA has a history of collaboration with foreign partners. Just this month, the agency joined Canadian and Australian cybersecurity agencies to issue a warning about an Iranian cyber offensive they said had been underway for more than a year, targeting critical infrastructure sectors including energy, government and information technology. (See Agencies Describe a Year of Iran Cyber Attacks.)
MISO Independent Market Monitor David Patton has made a final stand against the RTO’s $21.8 billion long-range transmission plan (LRTP) portfolio, asking MISO board members to order a postponement of the transmission portfolio and direct MISO to condense projects.
The appeal led multiple stakeholders to tell the MISO Board of Directors that the IMM should end his foray into MISO’s transmission planning and stick to supervising markets.
The showdown came as MISO advances its 2024 MISO Transmission Expansion Plan (MTEP 24) to its board of directors.
This year, MISO and members will vote on more than the traditional MTEP lineup. The MTEP 24 umbrella also officially includes the $21.8 billion LRTP and the $1.65 billion Joint Targeted Interconnection Queue (JTIQ) portfolio in partnership with SPP.
MISO staff have called the $30 billion collection historic.
In September, MISO’s Jeremiah Doner said even MTEP 24’s $6.7 billion of traditional local spending is a “sizable amount of investment occurring.” The traditional MTEP 24 includes 459 projects, with total lines spanning 932 miles.
Traditional MTEP 24 spending is smaller than last year’s $9.2 billion. And while a good chunk of MTEP 23 was devoted to local reliability needs, this year’s investment is driven by age condition projects and load growth.
However, it’s the second LRTP portfolio that’s soaking up all of the attention this year.
“Let me say at the outset: this is probably the least satisfying exercise I’ve taken part in. I take no pleasure in being critical of such an important process,” Patton told board members during an Oct. 30 teleconference of the System Planning Committee of the MISO Board of Directors. He added that he thinks transmission expansion is essential.
“We believe there are portfolios of transmission investment that will be extremely beneficial … but this portfolio is not that portfolio,” Patton said.
Patton said the “costly” portfolio represents a present value of $2,600 per family in the Midwest.
“Hence, it is critical that the analysis be objective, accurate and unbiased,” he said.
Patton said he wasn’t trying to thwart a second LRTP but that he wanted MISO to develop a leaner portfolio with downsized projects.
He said MISO’s two most flawed benefit metrics are the mitigation of reliability issues and the avoided construction of new capacity MISO estimates the portfolio will deliver on. He said if those two benefit calculations are downgraded to more reasonable outcomes, the benefit-to-cost ratio of the LRTP portfolio would be anywhere from 0.4 to 0.7:1.
MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the projects’ lives through reliability improvements, production costs, new capacity that won’t have to be built and environmental benefits.
Patton has said repeatedly MISO is incorrect in assuming reliability issues in the footprint would become so dire that MISO should use its $3,500/MWh value of lost load as an indicator of savings. He said a more reasonable notion is that MISO would take operational actions to address reliability risks.
Patton also said that MISO’s capacity expansion modeling is fundamentally flawed, favors intermittent resources and doesn’t consider what resources will be built and where if MISO doesn’t build the second LRTP portfolio. Patton said if MISO tested against a but-for scenario where there is no LTRP II, the footprint “rationally” would experience more capacity development in the eastern part of the footprint versus more remote, intermittent resources built in the western portion. He said any reasonable utility would choose to build deliverable megawatts without the transmission.
Patton likened MISO’s estimated benefits to trying to convince his wife to agree to buying him a new car instead of getting brake repairs performed on his existing car through the argument that his life would be at risk.
“That’s the logic you have to adopt: What is the alternative?” he said.
Planners Defend Portfolio
Senior Vice President of Planning and Operations Jennifer Curran said Patton and MISO philosophically disagree on the need for the LRTP portfolio.
“When we think about the resource expansion, we have a different idea about the goals of our customers and what our members are trying to achieve,” she said. “Where we agree is that we definitely need to do what’s best for our customers. That’s at the forefront.”
Curran said MISO requires backbone transmission and that waiting risks reliability and leaving the system expansion to less valuable, piecemeal transmission solutions.
“We cannot wait for the certainty of resource types to build transmission,” she said.
Curran said members’ stated goals provided the thrust for the portfolio. She stressed that MISO did not overstep its role as a transmission planner and not a resource planner.
The MISO IMM’s view of LRTP benefits in the second and fourth columns, which drastically reduce the portfolio’s benefits of avoided reliability risks and avoided new build capacity | Potomac Economics
“We are talking about the highway transmission and not the side streets,” she said.
Curran said MISO probably is being conservative in the reliability benefits and likely understating the help transmission would provide during extreme weather events. She said MISO stands ready to testify to the need for the transmission in front of state regulatory commissions.
Vice President of System Planning Aubrey Johnson said that the collection of 24 projects would create a backbone of mostly 765-kV transmission across the Midwest. He said MISO’s aims with the portfolio aren’t to address one NERC criteria at a time but “reliably enable” the resource planning its members have indicated. Johnson acknowledged that goal does shift the portfolio into “uncharted territory.”
Johnson noted that MISO planners made more than 500 adjustments to capacity expansion siting based on MISO members’ counsel.
Executive Director of Transmission Planning Laura Rauch said there are almost certainly additional benefits beyond those that MISO monetized in its business case, including more reliability and efficiency value and expanded transfer capability. Rauch said LRTP II will enable the sweeping flows that help keep the lights on during heat domes, derechos and ice storms.
MISO board members withheld their opinions on the LRTP and asked mostly clarifying questions on Patton’s criticisms and MISO’s process. They did not publicly address Patton’s appeal for a pause on the LRTP approval process.
“Is there a sense of, ‘don’t build and this [capacity] will evolve?’” board member Phyllis Currie asked of stakeholders’ attitudes across the 300-plus public meetings MISO held during the development of LRTP II. She said her question “strikes at the role of MISO” as a transmission planner and keeping out of resource planning.
Johnson said stakeholders generally were supportive of MISO’s direction on planning and confirmed to MISO that the proposed lines followed their burgeoning resource plans.
Board member Trip Doggett invoked a recent Grid Strategies report that placed MISO and CAISO at the top of regional planning efforts in the country, giving each a ‘B.’ Doggett asked what MISO should do to reach ‘A’ status. Curran said MISO’s grade boils down to the LRTP not yet extending to the MISO South region.
The System Planning Committee is set to hold a vote on whether to recommend MTEP 24 along with LRTP II at a Nov. 19 teleconference.
Chorus of Support, Some Detractors and Complaints that IMM has Overstepped
Most public comments after the IMM and MISO delivered their positions provided support for the LRTP, with multiple stakeholders telling MISO board members that the IMM shouldn’t be influencing transmission planning.
Michigan Public Service Commission staffer Erik Hanser said Patton is mistaken that “market forces alone” can fill the need for transmission planning.
Hanser also said Patton “bringing these issues up month after month” is not a good use of time for the Market Monitor, who he emphasized is not a transmission monitor. Hanser said he questioned how appropriate it was for the IMM to spend so much time and attention on an area outside of his market monitoring responsibilities.
Minnesota Public Utilities Commissioner Hwikwon Ham said MISO’s long-range transmission planning allows state jurisdictions to carry out their resource planning. He also said MISO’s comprehensive transmission planning saves ratepayers money over the long run.
American Transmission Co.’s Bob McKee said it’s inappropriate for the IMM to think his opinion on planning should override those of the stakeholder community. McKee invoked the LRTP as “exactly the type of long-range planning” that FERC is requiring RTOs to engage in per Order 1920.
McKee also said that LRTP II will go a long way in addressing the “new, unforecasted, historic, large-point loads” that are cropping up on the system and are requiring several out-of-cycle transmission projects.
Natalie McIntire, of the Natural Resources Defense Council’s Sustainable FERC Project, said the IMM simply seems opposed to top-down regional planning and said MISO is leading the industry in planning. She asked board members not to entertain the IMM’s requests.
WPPI Energy’s Steve Leovy, however, seconded the IMM’s ask for MISO to test the LRTP against a future case where the second LRTP portfolio doesn’t exist. He said the additional testing from MISO wouldn’t usurp the role of resource planning or infringe on states’ rights.
“Let’s be clear: The debate we are having today is not about methodology. It’s about ideology. And it’s being driven by Dr. Patton in ways that I believe are inappropriate for his position. I believe he has abandoned his independent voice,” Union of Concerned Scientists’ Sam Gomberg said.
Gomberg said it’s a “huge red flag” that Patton presented analytics showing the LRTP falls below worthwhile investment without documentation detailing his methods. MISO and stakeholders have “repeatedly suffered through” presentations on Patton’s uncorroborated numbers, Gomberg said, while Patton at times “belittles” MISO’s and stakeholders’ perspectives.
“Throw out any number you like in a public setting as long as it’s big enough to catch attention, let the media sink their hooks into it and the headline on the front-page reads: ‘IMM Says MISO Transmission Plan isn’t Worth It’ while everyone else scrambles to explain after-the-fact why this number shouldn’t be trusted,” Gomberg told board members. “When this happens, it makes yours and every state regulator’s job harder because it colors your and regulators’ ability to do the proper, objective due diligence necessary to weigh the costs and benefits of these projects.”
Gomberg said the IMM’s actions are “at best negligent and at worst a deliberate attempt to undermine the process.” He said he “believes it’s past time” for the MISO Board of Directors to “clearly and publicly” define the IMM’s role in MISO transmission planning and hold him accountable to transparency standards and analytic rigor.
“The character assassination of Dr. Patton is really unfortunate,” North Dakota Public Service Commissioner Julie Fedorchak said. “There’s a lot of opportunity between doing nothing and spending $30 billion in transmission planning.”
Fedorchak said MISO should listen to independent, third-party critiques that its LRTP business case is overblown.
“With these benefits, you could justify building just about anything,” Fedorchak said, reminding board members that North Dakota doesn’t have clean energy goals and it’s unfair for the state to shoulder a portion of LRTP costs.
Kavita Maini, a consultant representing MISO industrial customers, also said she appreciated the IMM’s request to take a hard look at the LRTP.
“We need an independent voice, and we appreciate the IMM’s efforts,” Maini said.
But Google’s Tyler Huebner said MISO’s “effective, multi-value transmission planning” is vital and serves as proof that not all members in the end-use sector agree with one another.
Clean Grid Alliance’s David Sapper said board members should “strongly” consider Google’s support since the LRTP is rooted in a future view of the grid, implying that Google should know better than most what’s to come.
ITC’s Brian Drumm said MISO assembled the second LRTP portfolio with industry-tested practices and planning tools that are crucial to maintaining reliability as the clean energy transition and load growth knock on MISO’s door.
“Now is not the time for us to slow down,” he said, endorsing the LRTP.
Drumm also said Patton’s “is just one voice” among hundreds of stakeholders who contributed to the multiyear development of the LRTP.
Great River Energy’s Priti Patel said she likewise was lending support to LRTP II. She said Great River Energy independently tested the LRTP’s business case and found that proposed lines in Minnesota best meet technical needs while minimizing impacts to communities across GRE’s electricity cooperative.
“We see this is a significant and necessary step to maintaining future reliability,” Patel said.
Xcel Energy’s Drew Siebenaler encouraged MISO and its board to proceed with the LRTP as soon as possible.
“In my professional career, I’ve never encountered a stakeholder process that has had more hours and engagement as this,” Iowa Utilities Board Member Josh Byrnes said of the journey to the second LRTP portfolio.
Byrnes said though “not everyone got what they wanted,” the LRTP has struck a good balance in planning.
“I truly believe that doing nothing is probably not a good option for us,” Byrnes said.
System Planning Committee Chair and MISO board member Mark Johnson thanked stakeholders for their perspectives.
FERC on Oct. 29 granted a complaint by Old Dominion Electric Cooperative (ODEC) filed against FirstEnergy and PJM alleging the utility overcharged it and asking for $18.6 million in refunds (EL24-121).
FirstEnergy’s Potomac Edison bills ODEC’s load in its territory through PJM based on information the RTO gets from the utility. The complaint alleged that FirstEnergy overcharged ODEC from July 2022 through the end of 2023 by including the load of Front Royal, Va., in the calculations when the co-op does not serve that municipality.
The utilities tried to work out the issue on their own, but FirstEnergy wanted to resettle the entire region because other utilities were undercharged, while ODEC wanted it taken care of bilaterally. FirstEnergy also wanted to pay ODEC only when it got money back from the other entities involved, but by the time the complaint was filed, it had not received any.
ODEC said it did not consent to FirstEnergy imposing the condition that it must resettle with all suppliers prior to providing it with refunds, FERC said.
The complaint asked FERC to find that ODEC was mischarged and that FirstEnergy failed to meet its obligation to timely effect a financial resettlement with PJM, and to direct repayment.
FirstEnergy argued that it was taking the proper steps to fix the mischarges and was working with the rest of the impacted entities to resettle, pursuant to PJM’s rules for resettlements. The only reason ODEC did not get any refunds was that it declined to take partial payments as the resettlement of the zone was occurring, the company argued.
ODEC said the rules do not require FirstEnergy to resettle the entire zone before paying back all that it owes the co-op. PJM agreed with this assessment in comments filed on the dispute.
FERC agreed that ODEC was overbilled because of the inclusion of Front Royal’s load, which led to it paying more than it owed for energy, capacity and transmission charges.
“FirstEnergy’s action in misattributing Front Royal’s load to ODEC was a violation of the filed rate,” FERC said. “Therefore, we grant the complaint and find that ODEC is entitled to reimbursement of the overcharges. …
“Nothing in the record supports FirstEnergy’s assertion that resettlement is required before providing a refund to ODEC. Indeed, PJM states in its answer to FirstEnergy’s answer that the PJM tariff and PJM processes do not require that FirstEnergy first resettle the entire wholesale market in its zone before refunding ODEC.”
Nothing in PJM’s rules applies to the situation in the complaint, so FERC said it was using its discretion to direct FirstEnergy to file a repayment plan to make ODEC whole plus interest within 60 days of the order’s issuance. FirstEnergy will have to discuss the plan with ODEC and indicate in that filing whether it has agreed on a plan with the co-op or explain why that did not happen.
