RTO Insider

October 31, 2024

Western Utility CEOs Reflect on Evolving Energy Markets

SACRAMENTO, Calif. — Leaders of four large utilities reflected on the evolution of Western markets and looked toward the future at CAISO’s Stakeholder Symposium on Oct. 30, emphasizing a shift toward more collaboration as large industry players choose which day-ahead market to join.

CAISO also announced the 10-year anniversary of the Western Energy Imbalance Market (WEIM), using it as a catalyst for conversation on what’s to come.

“How should we be thinking about the evolution of the markets in the West?” Lisa Grow, president and CEO of IDACORP and Idaho Power, said while moderating a panel at the symposium. “There are a lot of topical issues that we’re all thinking about and that surround the day-ahead market formation.”

Sitting on the panel was Cindy Crane, CEO of PacifiCorp; Tracey LeBeau, CEO of the Western Area Power Administration (WAPA); Dawn Lindell, CEO of Seattle City Light; and Caroline Winn, CEO of San Diego Gas & Electric (SDG&E).

PacifiCorp committed to join CAISO’s Extended Day-Ahead Market (EDAM) in April; Seattle City Light has signaled its intent to join; and SDG&E will join by default via its membership in CAISO. WAPA announced plans in October to study the benefits of joining.

PacifiCorp and SDG&E feel confident in the transition from WEIM to EDAM, citing CAISO data showing $6 billion in benefits from the WEIM since its inception and $1.4 billion in benefits in a fully implemented EDAM.

“We’re all in about creating more savings for our customers, and as we think about the grid development in the West and all of the investments that still need to be made for climate change, the clean energy transition and electrification, our customers need the savings to help offset some of those costs,” Winn said. “I just can’t think of a better time to really pursue EDAM.”

Studies done for PacifiCorp also demonstrated substantial benefits for customers by joining EDAM, Crane said.

“We just recently updated our EDAM study, and those studies have done nothing but substantiate that this is the best move for these markets in the West,” Crane said. “We firmly believe that EDAM will be a very successful and advanced energy market, and that it’s going to be what provides the ability for the sector to achieve and overcome the challenges that we currently have.”

Cindy Crane, CEO of PacifiCorp | © RTO Insider LLC

Some utilities indicated interest in EDAM but have not yet committed. In October, a group of Arizona cooperatives that account for 70% of WAPA’s Desert Southwest load announced a plan to study the benefits of joining EDAM. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.) The Brattle Group is doing a study for Seattle City Light that will evaluate the benefits of joining EDAM or SPP’s Markets + that is expected to be published in December.

For those that have yet to formally commit, leaders agree that choosing a market that will bring the most value and connectivity to customers, as well as accelerating decarbonization efforts, is top of mind.

“We’re in the throes of our decision-making, and customer-benefit analysis will be key in deciding what market we go to,” Lindell said.

‘The Fewer Seams, the Better’

Market seams are bound to be an inevitable challenge, as it may be more difficult to trade power to and from balancing authority areas operating in different day-ahead markets.

The CEOs emphasized the importance of collaboration through seams agreements, especially to support each other through increasingly frequent extreme weather events.

“We’re committed, first and foremost, to making sure that we have seams agreements in place,” Crane said. “But [seams] do create a loss of efficiency in the system. And seams agreements don’t overcome the loss of efficiency.”

WAPA shares a seam with MISO, and while LeBeau said it isn’t ideal, “it’s been going pretty well.” She pointed to the relationship that has been developing between MISO and SPP as a good example of collaboration for the West to follow.

Lindell agreed that the “fewer seams, the better,” pointing again to the inefficiencies they create, as well as the rise in risk for speculative trading and overall increased costs.

“We all operate parts of, I think, the most complex machine that humans have ever built, and it requires collaboration and coordination,” Winn agreed. “There’s some competition that’s built into the markets, for sure, but having spent most of my life in this industry, it’s such an honor to be able to serve in that way and provide such a basic service that everyone relies on.”

October 31, 2024

Exelon Reports 80% Increase in Data Center Forecasts in 3rd-Quarter Earnings

Estimates of data center growth across Exelon’s service regions have increased by about 80% since the year began, executives said during the utility’s third-quarter earnings call. They predicted steady growth in transmission upgrades and a regulatory battle to define the grid service costs applicable to data centers that co-locate with generators.

Exelon CEO Calvin Butler said it now forecasts 11 GW of high-probability data center load, up from 6 GW at the start of 2024. While that presents an opportunity for growth, he stressed that getting that load interconnected must be done in a coordinated, thoughtful and efficient manner to yield “transparent, forward-looking planning and ratemaking.”

That goal underlies its advocacy at FERC, PJM and legislatures to ensure that co-located load configurations pay for any grid services they benefit from and are studied for any reliability implications. (See Exelon, Constellation at Loggerheads over Data Center Co-location.)

Data centers seek to co-locate with several nuclear generators in their search for carbon-free power, including Constellation’s Calvert Cliffs Nuclear Power Plant in Maryland, Limerick Nuclear Power Plant in Pennsylvania and Talen’s Susquehanna Nuclear Plant.

Exelon COO Michael Innocenzo said co-located configurations can have several impacts on the grid that would not be recognized under the proposals from Constellation and Talen. Those include ancillary services the load benefits from by nature of drawing off a generator that itself is interconnected, as well as grid upgrades that may be prompted by removing that capacity from PJM’s system.

“Our whole position has just been — if they can co-locate, if they can get in there quick and get in there doing what they want to do, we support that. We just want to make sure that it has the appropriate transparency on what they are doing. We want to make sure that we have the appropriate studies done to make sure that we are addressing resource and reliability and adequacy currently, and we also want appropriate rate design to be able to cover for those costs, either now or in the future,” Innocenzo added.

More generation also will be needed to meet that load growth, which Butler said will require changes to PJM’s capacity market structure to ensure increasing costs don’t compromise the goal of efficiently meeting demand. While Exelon is not advocating for an expansion of regulated generation, he said it’s engaging in discussions with other utilities and regulators on the subject.

“And I do appreciate PJM’s leadership to put forward interconnection and various capacity and market reforms. And it’s just another example that the PJM stakeholder process is just not working. And we will continue to support them as well as other federal and regional agencies to get that done,” Butler said.

Quarterly Earnings on Pace with Projections

Earnings continued to be on track to meet the utility’s guidance of $2.40 to $2.50 earnings per share, with quarterly earnings 4 cents higher compared to Q3 2023 due to the timing of ComEd’s distribution earnings. Higher distribution and transmission rates increased earnings another 3 cents, which were equally offset by higher interest rates.

Final orders on rate bases for ComEd and PECO are expected from the Illinois Commerce Commission (ICC) and Pennsylvania Public Utilities Commission (PA PUC) within the next few months, which would cover about half of Exelon’s total base. Butler said the utility plans to make $34.5 billion in capital investments between 2024 and 2027, increasing rate base by about 7.5%.

The use of multiyear plans in several states offers additional transparency and affordability for consumers and allows Exelon to build on its long-term plans more effectively, Butler said.

Exelon CFO Jeanne Jones said the utility’s transmission projects already are leading to cost savings for consumers, with upgrades to bring the Vienna-Nelson from 138-kV to 230-kV running two years ahead of scheduled. Once that’s complete, Indian River Unit 4 will be able to finish its deactivation, potentially leading to an early end to a reliability must-run (RMR) contract with NRG Energy to keep the generator operational. If that agreement were to terminate two years early, Jones said it would save ratepayers nearly $100 million, more than 1.5 times the cost of the transmission upgrades. (See PJM OC Briefs: July 11, 2024.)

October 31, 2024

Xcel Welcomes Load Growth from Data Centers

Xcel Energy CEO Bob Frenzel welcomes the coming wave of data centers, despite the increased demand they will place on the grid.

Frenzel told financial analysts during the company’s third-quarter earnings conference call Oct. 31 that Xcel has nearly 9 GW of “opportunities” before 2030 in the customer pipeline. He said the company expects about a quarter of those projects will secure contracts during the next five years.

“The scale of this pipeline gives us the ability to thoughtfully negotiate agreements that deliver the energy and capacity needed to important new customers in the region [and ensure] that new data center load that’s brought onto our system benefits all customers,” Frenzel said. “It drives load growth to our increasingly decarbonized energy system, generates economic growth in vitality in our communities and delivers on the national imperative to support a domestic data center industry.”

As the large loads come looking for transmission and generation service, Frenzel said, they highlight a different need.

“We, as a country, [and] we, as an industry, need to be accelerating our ability to develop both transmission and generation to serve the load that we think is going to come. It’s meaningful load. If you can provide it across the entire country, it seems manageable as you get into very specific load pockets; it comes with a lot of need and a lot of speed that’s needed,” he said.

“We’re starting to see this energy transition we’ve been talking about and working on for the past five years really start to accelerate. We’re proactively removing our coal plants from the system and replacing them with cleaner and, in some cases, lower-cost generation resources,” Frenzel added. “I think that is an opportunity for us to mitigate cost increases across the entire country as we transition both our transmission and generation footprint for the next generation.”

The Minneapolis-based company reported third-quarter earnings of $682 million ($1.21/share), compared with $656 million ($1.19/share) in the same period in 2023.

Xcel also introduced its new five-year, $45 billion investment plan, with a focus on four key areas, Frenzel said: clean energy, customer electrification, new load growth, and safety and reliability.

The company’s share price was up nearly 6% on Oct. 31 at $66.81, a $3.76 gain from its previous close.

October 31, 2024

Rosner Hopeful for Consensus on Order 1920 Rehearing

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.”

October 31, 2024

Entergy to Pay SERC $141K for Standard Violations

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.

October 31, 2024

WINDPOWER: Lessons Learned from Early Offshore Efforts

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.”

October 31, 2024

ISO-NE Study Lays Out Challenges of Deep Decarbonization

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.

October 31, 2024

WINDPOWER: Industry Puts on Game Face as Election Nears

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.

Vineyard Offshore CEO Alicia Barton speaks with American Clean Power Association CEO Jason Grumet, left, and Atlantic Shores Offshore Wind CEO Joris Veldhoven at Offshore WINDPOWER 2024 on Oct. 29. | © RTO Insider LLC

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.”

October 31, 2024

FERC Grants SPP Waiver for GI Queue Backlog

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.)

October 30, 2024

WAPA Sierra Nevada Region to Advance with EDAM

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.”