FERC has largely approved Order 2023 compliance filings for four utilities in the West and Texas, directing them to submit further compliance filings within 60 days.
The utilities include Idaho Power (ER24-10), Puget Sound Energy (ER24-1559), Black Hills Colorado Electric (ER24-2023) and Golden Spread Electric Cooperative (ER24-2027).
FERC approved Order 2023 in July 2023 to revise its pro forma generator interconnection rules to speed up processes in backlogged interconnection queues throughout the U.S. (See FERC Updates Interconnection Queue Process with Order 2023.)
The order changed the commission’s pro forma interconnection rules to require transmission service providers to shift their approach to interconnection from a first-come, first-served serial process to a first-ready, first-served cluster process; increase the speed of queue processing; and incorporate technological advancements such as grid-enhancing technologies into the process.
FERC in March partly approved Idaho Power’s initial Order 2023 filing, asking the utility to align its interconnect procedures with the order’s requirements related to the cluster study process, the allocation of cluster network upgrade costs and site control. (See FERC Upholds, Clarifies Generator Interconnection Rule.)
The commission also had asked the utility “to either justify unexplained variations as consistent with or superior to the commission’s pro forma procedures and agreements or adopt without modification the commission’s pro forma procedures and agreements” and to remove proposed tariff revisions that exceeded the scope of the order.
In its Sept. 19 ruling, FERC approved revisions to Idaho Power’s initial filing related to the cluster study process, allocation of upgrade study costs and site control, noting the utility largely adopted the commission’s pro forma rules except for “minor variations.” The commission made a similar finding on the utility’s rules around site control and the transition to the “first-ready, first-served” cluster process and affected system study process.
FERC additionally said Idaho Power had satisfied the commission’s request that it rescind previously proposed revisions to the utility’s surplus interconnection service rules that were determined to be outside the scope of Order 2023 but directed the utility to delete a section of the tariff related to those rules within 60 days.
The commission issued similar rulings for the other three utilities, finding their proposed tariff revisions largely compliant with Order 2023 but requiring each to submit additional compliance filings within 60 days to account for minor shortcomings in their previous filings.
The sticking points for Puget Sound Energy’s filing centered around “unexplained” deviations from the pro forma language in the utility’s revisions related to its cluster network upgrade cost rules and affected system agreements.
In its order on the Black Hills Colorado filing, FERC approved the utility’s deviations from pro forma rules related to operating assumptions for interconnection studies, specifically its practice of not determining the network upgrades required for a charging electric storage resource in its interconnection study process because, when charging, a storage resource “looks and acts more like load than an injecting generator.” Black Hills said instead it would determine the impact of those resources through the transmission service request process.
The commission’s partial approval of Golden Spread’s filing included a rejection of the co-op’s removal of pro forma language saying that, for transmission providers that employ fuel-based dispatch assumptions, “a request to add a generating facility of a different fuel type to an existing interconnection request would always constitute a modification that would require study.” Golden Spread omitted that language, saying it doesn’t use fuel-based dispatch assumptions, but the commission directed it to restore the language in an additional compliance filing.
A city bus trundled to a halt on a dusty gravel road just south of Albany at the Port of Albany’s offshore wind expansion project. The passengers, various representatives from labor, the energy industry and the Alliance for Clean Energy New York, shielded their eyes from the late afternoon sun, staring across several acres of flat, riverside land.
“If you look out to the east side, you’ll see a line of trees that stretches about eight acres,” said Richard Hendrick, CEO of the Port of Albany. “We engaged early on with the First Nations people who have sacred land on the east side of the Hudson River. … They suggested if we just keep that buffer of trees, none of what we’re doing here will impact their view.”
Hendrick and his staff proudly showed off the newly created, fully permitted site they hope will be the center of offshore wind tower manufacturing for New York’s emerging market. Hendrick’s team had removed 30,000 tons of contaminated coal ash from roughly 100 acres of land and capped off the rest of the soil. Construction is entering final stages on a 400-foot steel bridge to connect the site to the rest of the port over a nearby creek.
Construction on a 500-foot wharf and dedicated substation are due to begin in early 2025.
Optimistic Outlook
The tour, forward looking and full of hope, put a period on the general theme of the Alliance for Clean Energy NY’s fall conference. Industry players, regulators and elected officials generally were positive about the direction of New York’s energy future despite recent reporting that the state would fall short of its 2030 climate goals.
“Our pipeline continues to grow,” said Doreen Harris, president of NYSERDA, in her breakfast keynote address. “We have over 100 large-scale renewable projects in the interconnection queue. … These projects are getting built! Some of you may know that I’ve coined that summer of 2024 is the ‘Summer of Shovels,’ and you have kept me very busy celebrating.”
Harris said that just 10 years ago, the renewable picture wasn’t nearly as robust. She pointed to 1 GW of distributed solar installed last year and compared it to the roughly 50 MW the state was installing a decade ago.
“If you take nothing else from these remarks, I want you to know that the renewable energy pie will continue to grow here in New York in the coming decades,” Harris said. She said her goal is to accelerate the progress on renewables, and she encouraged industry representatives to participate in developing the new Clean Energy Standard.
“The phoenix has risen from the ashes here in New York, and we have collectively emerged stronger, smarter, wiser and more powerful,” she said. “Make no mistake: This was a Herculean effort. But here in New York, we deliver on our promises.”
Speeding up progress on siting, permitting and interconnection was the major theme of the morning’s panel discussions. Department of Environmental Conservation interim Commissioner Sean Mahar told attendees he didn’t want the DEC to be a barrier to renewable development.
“What we think we’re doing right now is creating a more workable program,” Mahar said, referencing wetland regulations. “We are structuring this program in the right way so as not to be a barrier to development, but to make sure development is happening in the right places.”
In later comments, Mahar said DEC is working on ways to permit renewable energy development on brownfields and Superfund sites, to streamline the permitting process and to streamline mitigation efforts in places where renewables harm the environment.
Zach Smith, vice president of system and resource planning for NYISO, said the ISO implemented a new interconnection process to speed up the expansion of transmission and renewables.
“Our projection is that roughly three times the amount of generating capacity is needed in the next 20 years relative to today’s system. Opportunities abound,” Smith said. “What that capacity looks like, that’s kind of a big question mark. There is not a single formula to this.”
Smith said the upcoming Reliability Needs Assessment was conservative in its estimate of how much generation capacity would be interconnected. Some projects in the interconnection queue weren’t considered as part of the assessment because they weren’t far enough along. He said a finding of a reliability need wasn’t necessarily “pulling the fire alarm.”
“Rather, it’s to flag the need for continued progress on resources in New York State, and we have had many,” Smith said. “It’s an opportunity for further resource development.”
Endorsements for New York’s Renewable Market and Kamala Harris
A lunch panel of renewable energy industry leaders said they were broadly optimistic about building new energy resources in New York.
“The main point here is that you have a very strong market signal about demand in New York, which makes it an attractive place to really think about a multiyearlong investment program,” said Ben Koffel, chief commercial officer of Vineyard Offshore. He pointed to the high forecast load growth for the state. “If you were at this kind of conference a decade ago, people weren’t talking about that. Everyone was talking about energy efficiency.”
He said load growth in New York, combined with the state’s willingness to “put its neck out there and be a leader,” made the state attractive to energy investors.
“We don’t see a tremendous amount of opportunity cost because New York is such a leader, particularly in the offshore space,” Koffel said. “This is a marquee market globally. That’s what we hear from our peers in Europe.”
Mark Richardson, CEO of US Light Energy, a distributed solar energy company, was less enthusiastic about the near term for his industry segment in the state.
“Where the rubber hits the road in terms of deployment, distributed generation has been incredibly successful over the past several years,” Richardson said. “From our perspective, the opportunity in that segment has slowed down dramatically, and it’s a combination of infrastructure capacity, interconnection capacity, interconnection queues … combined with a local stranglehold on the permitting process for smaller projects.”
Richardson said New York, so far, has done a good job, but the distributed generation segment needs more help from the state to deal with local siting and permitting issues.
Clint Plummer, CEO of Rise Light and Power, said the industry had to find ways to get as much community support as it could while also designing projects that would be minimally impactful.
“People don’t want big things in their backyards,” Plummer said. “As a resident, I like that my voice has some impact on what can be built in my community where I live, and as a developer, it’s a major source of annoyance. But it’s a necessity.”
Plummer said this meant going to public meetings and being willing to take the “endless barrage of criticism” that they bring, then adapting plans to mitigate, or avoid, impacts.
“You’re never going to win everybody, but people will respect you for being a trustworthy partner,” Plummer said.
Later, during a “lightning round” question, the topic of the election was brought up to the panel.
“I hope a year from now, Doreen is not the only President Harris that we know,” Plummer said. “But practically speaking, this underscores why New York is a good place to be investing.”
Plummer explained that a Harris presidency probably would be more pro-renewable than a second Trump administration. But if Trump were elected, New York’s position of pushing for more renewable generation for the state still would make it an attractive spot to develop.
Koffel said that even if Trump wins, New York has a strong economic case for renewables now that the industry had gotten to its current size.
“Renewables is a big tent, and the industry touches a lot of people,” Koffel said. “In the event that Trump is the president again, that tent will mobilize to talk about the benefits it’s bringing to the region, the billions and billions of dollars of investment.”
Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers.
Constellation announced the reopening in a press release Sept. 20, exactly five years after it took the nuclear generator offline for economic reasons. In its new life, the generator has been renamed the Crane Clean Energy Center (CCEC) in memory of Exelon CEO Chris Crane, who died in April 2024. (See Exelon to Close Three Mile Island.)
“Powering industries critical to our nation’s global economic and technological competitiveness, including data centers, requires an abundance of energy that is carbon-free and reliable every hour of every day, and nuclear plants are the only energy sources that can consistently deliver on that promise,” Constellation CEO Joe Dominguez said in the announcement. “Before it was prematurely shuttered due to poor economics, this plant was among the safest and most reliable nuclear plants on the grid, and we look forward to bringing it back with a new name and a renewed mission to serve as an economic engine for Pennsylvania.”
Constellation aims to bring the unit back online in 2028 and will seek a license renewal from the Nuclear Regulatory Commission to continue operating the generator through at least 2054. Restarting the unit will require a $1.6 billion investment, including upgrades to the turbine, generator and transformer. Safety and environmental reviews will be required from the NRC, as well as local and state permits. The adjacent TMI Unit 2, which partially melted down in 1979, is owned by Energy Solutions and is in the process of being decommissioned.
Microsoft Vice President of Energy Bobby Hollis said the carbon-free energy provided by CCEC will help the company meet its clean energy targets. The PPA will be effective for 20 years.
“This agreement is a major milestone in Microsoft’s efforts to help decarbonize the grid in support of our commitment to become carbon negative. Microsoft continues to collaborate with energy providers to develop carbon-free energy sources to help meet the grid’s capacity and reliability needs,” he said.
Data center load has been a significant driver of rapidly increasing load forecasts in PJM and has been highlighted as one factor behind a spike in capacity prices in the 2025/26 capacity auction. (See “PJM Discusses 2025/26 Auction Results,” PJM MRC/MC Briefs: Aug. 21, 2024.)
The RTO’s 2024 load forecast, which is based on historic economic trends, includes large load additions in the AEP, APS, Dominion and PS zones, reflecting changes in consumption that utilities identified. Dominion estimated 2,666 MW of additional load in 2025, which it estimates will balloon to 21,563 MW in 2039. American Electric Power estimates 1,738 MW in 2025, growing to 3,624 MW in 2039.
Data centers have sought to co-locate with nuclear power plants, which would pull capacity out of PJM’s market over the objections of utilities and state regulators. Talen Energy and Amazon Web Services reached an agreement earlier this year to sell a data center Talen built adjacent to its Susquehanna Nuclear Plant and supply it with behind-the-meter energy.
PJM has asked FERC to approve an amendment to the generator’s interconnection service agreement to reduce the maximum output, and capacity, the generator offers into PJM. Exelon and AEP filed a joint protest arguing that co-located load benefits from the wider transmission grid and should be subject to relevant fees. They also argued there are unresolved questions about how a novel configuration could affect the grid. The Pennsylvania Public Utility Commission filed in support of the utilities’ protest (ER24-2172). (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)
Pennsylvania Politicians, Nuclear Experts Support Reopening
Pennsylvania Gov. Josh Shapiro (D) gave the reopening his support in a statement provided through Constellation’s announcement, saying the state’s nuclear industry provides “safe, reliable, carbon-free electricity.”
“Under the careful watch of state and federal authorities, the Crane Clean Energy Center will safely utilize existing infrastructure to sustain and expand nuclear power in the commonwealth while creating thousands of energy jobs and strengthening Pennsylvania’s legacy as a national energy leader.”
That support was echoed by state Rep. Tom Mehaffie (R), U.S. Rep. Scott Perry (R) and Bart Shellenhamer, chair of the Board of Supervisors for Londonderry Township, where the CCEC is located.
“This unit was a good neighbor to Londonderry Township and our surrounding region for 45 years, with a workforce dedicated to contributing to area nonprofits and supporting the local economy,” Shellenhamer said. “The Crane Clean Energy Center will bring billions in new infrastructure investment and help support area businesses, schools and public services that improve quality of life for the whole region.”
Michael Goff, acting assistant secretary of the U.S. Department of Energy’s Office of Nuclear Energy, said the reopening is a milestone for Pennsylvania and the country. “Always-on, carbon-free nuclear energy plays an important role in the fight against climate change and meeting the country’s growing energy demands,” he said.
Constellation purchased TMI 1 in 1999 and operated the unit through 2019, when it opted to deactivate the generator rather than buy more fuel. The company asked the Pennsylvania General Assembly to pass subsidies for the plant’s continued operation years ahead of the retirement. While both chambers had bills on their dockets, their prospects were unclear. (See Pa. Lawmaker Contends TMI Rescue Unlikely.)
The three independent SPP board members providing oversight of the RTO’s Markets+ development in the West have called for policy- and decision-makers to allow the process to “follow its natural course.”
In an open letter released Sept. 19 and addressed to the Pacific Northwest congressional delegation, Western state regulators and the stakeholder-led Markets+ Participant Executive Committee (MPEC), the directors said delaying decisions to allow other market options to more fully develop will lead to uncertainty and prevent some interested participants from benefiting.
“Extended delays could lead to market participant uncertainty about their market choices and, due to the need for adequate market footprint for Markets+ to succeed, deny interested parties the possibility of becoming beneficiaries of its unique design,” wrote Director Steve Wright, chair of the Interim Markets+ Independent Panel (IMIP), fellow SPP Director Elizabeth Moore and board Chair John Cupparo.
“This independent panel understands some parties’ wishes to delay decisions while other market options more fully develop. Making Markets+ a reality requires continued funding, though, and funding requires that Western entities be allowed to negotiate and execute agreements on the defined timeline,” the IMIP said. Western market participants “were clear that anything other than accelerated market development” would undermine the day-ahead market’s viability and would “hence not be worth their time or money.”
“It is our belief that the accelerated formation of the Markets+ option has already provided benefit to Western consumers,” the IMIP said. “There are many examples of competition improving market design and governance of several market alternatives that will be available to the West.
“SPP and participants in Markets+ development anticipated short delays for steps like FERC tariff approval, but longer delays could disrupt healthy competition, threaten an as-soon-as-possible go-live date for Markets+ and ultimately deny the West a solution to many of the challenges it faces,” the directors added.
The RTO has been involved with several service offerings in the Western Interconnection, some that predate the COVID-19 pandemic. It was approached in 2021 by Western entities interested in designing a market. Work with 37 stakeholders began the next year and has resulted in a governance structure that has produced a tariff and market protocols.
As if to emphasize the need for speed, SPP filed a response to FERC’s deficiency letter Sept. 20, more than a week ahead of the due date. The RTO said the deficiency letter is part of a “routine process” it has been participating in for years. It said none of the commission’s questions indicate a “serious risk.” (See SPP Dispels Concerns over Markets+ Deficiency Letter.)
The grid operator used 33 pages to answer the 16 questions, which dealt largely with transmission issues. It asked FERC for an order by Nov. 20.
The IMIP said the deficiency letter was “consistent with our expectations” for the market’s approval and that SPP’s response to FERC “falls within its previously adopted schedule.”
The panel’s comments come as efforts to build two day-ahead markets in the West continue to ratchet up.
In recent months, the four U.S. senators from Washington and Oregon have urged the Bonneville Power Administration, one of the key Market+ players, to “act carefully and deliberately” before choosing a market. The agency has responded by reiterating its resistance to the CAISO Extended Day-Ahead Market’s (EDAM) California-centric governance model and expressed support for SPP’s market. BPA has delayed a decision until 2025, but it also plans to continue its funding in the second phase of the market’s development. (See ‘Leaning’ Evident in BPA Response to NW Senators and BPA to Fund Phase 2 of Markets+, Agency Exec Says.)
CAISO in June kicked off a West-wide Governance Pathways Initiative designed to shift the ISO’s governance structure to an independent entity within the EDAM. Four workshops have highlighted the difficulty of designing a new Western “regional organization.” (See related story, Comments on Western RO Stakeholder Plan Show Complexity of Effort.)
While potential participants consider which market to join, some have already made that choice. NV Energy announced its intention to join EDAM, and two Black Hills Energy subsidiaries said they will leave SPP’s Western Energy Imbalance Service for CAISO’s Western Energy Imbalance Market. Black Hills participated in Markets+’s first phase and said it will pursue markets that “provide additional value.”
“Organizations spanning the Pacific Northwest, Desert Southwest and Mountain West regions will weigh many factors in making decisions about participating in a regional electricity market,” the IMIP said. “We trust they’ll each make the ultimate choice that’s best for their respective stakeholders.”
The directors said SPP has approved a $150 million budget for the market’s remaining development, “a fraction of a percent of the $25 billion in transactions that occur annually in Western wholesale trading markets today.” They said Markets+’s governance and market design will offset upfront costs, with the RTO’s experience operating other markets suggesting that Markets+ services will have a lower lifecycle cost than other alternatives.
According to SPP, BPA will be responsible for at least 17.4% of Phase 2 funding, second only to Powerex at 23.2%. Those percentages could increase should the Black Hills subsidiaries withdraw from further Markets+ development efforts.
MSC, IMIP Strengthen Relationship
The Markets+ State Committee, comprising Western regulators and one of the recipients of the IMIP’s letter, has endorsed a resolution that provides greater cooperation between the commissioners and the IMIP.
The two bodies have agreed to participate in each other’s meetings with allocated time on their corresponding agendas. They also agreed to host joint in-person or virtual meetings to address any issues during the market’s development and operation.
Director Wright has indicated to the MSC that the IMIP will support the resolution.
The MSC meets monthly, while the IMIP generally meets during MPEC meetings.
Hybrid power plants, especially projects combining solar and storage, represent a growing amount of new generation online and in interconnection queues across the U.S., signaling a shift in how renewable power can be integrated into electric power markets, according to a new report from the Lawrence Berkeley National Laboratory.
As of the end of 2023, the U.S. had 469 hybrid power plants of 1 MW or greater, with a total of 49 GW of generating capacity and 9.9 GW of storage, the report says, drawing on information from the Energy Information Administration. Solar-and-storage projects made up 288, or more than 60%, of that total, with 14.4 GW of generation and 7.7 GW of storage.
Other topline numbers show that 66 of the 80 new hybrid plants coming online last year were solar-and-storage. Such hybrids also account for 55% of solar generation capacity and 52% of storage capacity actively moving through interconnection queues.
According to LBNL, as of the end of 2023, 2,532 solar-and-storage hybrids with more than 575 GW of power were in U.S. interconnection queues.
Further, the report notes that 46% of all online storage capacity is coming from hybrid plants versus 42% from standalone projects. In terms of energy ― actual megawatt-hours produced ― hybrid storage is outperforming standalone, 52% to 38%.
Will Gorman, a research scientist at LBNL and lead author of the report, said the emergence of hybrid solar-and-storage is a relatively new trend over the past few years, spurred by the increase in solar on the grid, especially in places like California and Texas.
“There is a certain appetite for PV to just come onto the system without any kind of storage getting paired,” Gorman said in an interview with RTO Insider. “But once you get to a certain saturation point, which we certainly have started to see in California … you see that solar in particular is very synergistic with batteries.”
Solar currently generates about 30% of California’s electricity, according to the Solar Energy Industries Association.
Market saturation, along with falling battery prices, has triggered an inflection point, Gorman said, “and it was like, ‘Oh wow, we can basically create a dispatchable generator in a way, by pairing these two resources [at] a fairly competitively priced amount that wasn’t really possible three or four years ago.’”
With solar providing an increasing amount of new generation on the grid ― 54% in 2023, according to the National Renewable Energy Laboratory ― Gorman estimates that solar-and-storage hybrids made up about 25 to 30% of that new solar. California and Texas have the most hybrid capacity, but Massachusetts has the highest number of solar-and-storage hybrids ― 89 ― although they are smaller plants, with a total capacity of less than 7 MW.
California’s 72 hybrids include 30 projects with more than 100 MW of solar; for example, the Slate solar-and-storage project, which came online in Kings County in 2022, has 390 MW of solar and 140 MW of storage with four hours of duration.
Arizona led the nation for new solar-and-storage hybrids in 2023, with 16 plants coming online.
In addition to solar and storage, the LBNL report includes a long list of other types of hybrid plants in operation, including wind and storage (19 projects), fossil fuels and storage (28), nuclear and fossil (four), and geothermal and solar (seven). Hydropower paired with biomass, fossil fuels or storage also is on the list, as are triple combinations such as wind, solar and storage, and geothermal, PV and concentrated solar power.
Hybrid Synergies
As noted by Gorman, the emergence of hybrid plants has paralleled the growth of renewables on the grid and the need for new carbon-free resources that can provide the grid services, flexibility and dispatchability of traditional generation, such as natural gas peaker plants.
Federal tax credits — or rather, the lack of them — were another early driver. Prior to the passage of the Inflation Reduction Act in 2022, a tax credit for standalone storage did not exist. To cash in on the 30% federal investment tax credit (ITC) for solar, storage had to be connected to a solar project where it could charge off the PV panels at least 75% of the time.
The IRA provided a 30% ITC for standalone storage, similar to the solar tax credit. But, Gorman said, the ongoing growth of PV-and-storage projects could indicate the hybrid trend is not “just some type of tax-driven construct. There are real synergies behind the things that are getting paired and extracting value from the markets we’ve set up.”
The report tracks key data points that reflect evolving market dynamics.
Solar-and-storage projects generally have a higher ratio of storage to generation than other hybrids. Gorman defines a project’s “storage-to-generation ratio” as the amount of storage per 1 MW of generation capacity. In the LBNL report, the storage ratio for PV-and-storage projects averages out to 54%, versus 18% for wind-and-storage hybrids and 21% for fossil fuels and storage.
Grid services are the primary use for hybrid power plants, except for PV-and-storage projects, which are increasingly being used to firm renewable power and minimize the need for curtailment. | Lawrence Berkeley National Lab
The higher ratio means these projects can store more of the excess solar energy produced at off-peak times to meet demand during peak load times, Gorman said. “You need more storage capacity to be able to absorb more of that solar energy,” he said.
The higher storage capacity of these projects also is leveraged in how they are used. While many solar-and-storage plants are designed to take advantage of multiple uses and revenue streams, the report notes that in 2023, EIA started asking hybrid plant operators to provide information on their projects’ primary use.
Grid services ― an umbrella term covering frequency regulation, ramping, load following and voltage support ― were the top primary use for most hybrids, except solar-and-storage projects, the report says. The primary use there has been system firming for renewable power and minimizing curtailment, while standalone storage projects increasingly are being used for arbitrage.
Gorman again sees the difference as a result of market evolution: Being able to time-shift power from off-peak to peak demand hours is increasingly valuable. “In the past, batteries were mostly providing these kind of reserve values, providing grid services available on demand,” he said. “Now that [developers] have started to see some price differentials in the markets that are beneficial to arbitrage, they’ve added daily cycling on top of that.”
At the same time, prices on power purchase agreements for solar-and-storage hybrids are going up in line with their increased value on the grid, as well as the impacts of inflation and supply chain constraints that have affected solar and storage in general. From 2018 through 2021, PPA prices were relatively flat, coming in around $40/MWh, Gorman said. But prices have edged up since 2022, moving toward $60 to $80/MWh.
But Gorman cautioned that PPA prices “don’t reflect costs. PPA prices are a mixture of supply and demand.” If demand for battery storage goes up, he said, hybrid solar-and-storage projects may be perceived as more valuable.
Capacity Markets and Queues
In addition to the IRA, expansion of the hybrid market also could be affected by FERC Order 2023, issued in July 2023, the report says. The order allows more than one form of generation or storage to co-locate on a single site with a single point of interconnection and be treated as a single project in a grid operator’s interconnection queue. (See FERC Updates Interconnection Queue Process with Order 2023.)
Projects in the queue also can add a resource in certain circumstances without losing their place in the queue; for example, a solar project adding storage that does not materially change its interconnection application.
By the end of 2023, 469 hybrid power plants were online across the U.S. | Lawrence Berkeley National Lab
Hybrids’ impact on grid flexibility and reliability also may depend on their participation in RTO and ISO capacity markets, which in turn could depend on how individual grid operators value them. According to the report, valuation methods are in transition across the country.
In 2023, CAISO valuation was based on a method combining effective load-carrying capacity (ELCC) and sum of parts. ELCC quantifies how much additional load a resource can support on the grid while maintaining reliability, while sum-of-parts valuation quantifies individual components of a hybrid and then combines them to determine an overall capacity value.
CAISO plans for a 2025 transition to a “slice of day” method that will value plants according to their performance in every hour during the highest peak-load day of each month.
Similarly, the trend among other RTOs and ISOs is toward more targeted valuation methods. MISO has gone from a yearly valuation of a plant’s output during the top eight peak demand hours to a seasonal framework in which capacity value is based on peak output in each season.
LBNL has research underway looking at which valuation methods might best reflect and optimize the different capabilities of hybrids and benefit the grid, Gorman said.
Whether Order 2023 will help get more solar-and-storage hybrids interconnected remains an open question. The rule is aimed, at least in part, at shortening queues by limiting the number of “speculative” projects seeking interconnection.
Gorman recognizes that, like other projects, not all hybrids will make it through the queues. But, he said, “I think the ‘speculative’ term is charged. At LBNL, we try to maintain neutrality. If you talk to transmission providers, they will use ‘speculative.’ If you talk to the developers, they will tell you that the inherent uncertainty of the process requires them to discover how expensive it is to connect to the system, and since it takes so long to make it through the queues, they have to submit multiple requests.”
Still, hybrids may have an edge. “There is an interconnection strategy to hybridizing,” Gorman said. “Since these queues are so backlogged, instead of submitting two applications, FERC has now allowed that these hybridizing plants can go in as one … not skipping the queue per se, but sometimes avoiding some of the pain of the queue.”
INDIANAPOLIS — The MISO Board of Directors hit the high notes of resource adequacy anxiety, a possible board addition with experience at Southern California Edison and an annual budget that will creep past $400 million for the first time.
More Supply Alarms
In what’s becoming a familiar refrain, Senior Vice President of Markets and Digital Strategy Todd Ramey cautioned board members that MISO’s capacity soon will fall short of serving ever-increasing load.
MISO needs a “dramatically accelerated pace of new build,” Ramey said at a Sept. 19 board meeting. He stressed the RTO needs dispatchable, long-duration resources, noting that member plans submitted under MISO’s 2024 Regional Resource Assessment show anticipated additions primarily are weather-dependent.
Ramey said members should consider “deferring retirements until other options are available.” He also said members might question whether their clean energy goals “balance and add up well” against reliability requirements. He said some could relax target time frames.
“Without delays we’ve had to date, we’d be in a whole lot of trouble,” MISO Director Todd Raba said.
However, MISO Director Mark Johnson said retirement delays should be considered “as short-term lever.”
Director Phyllis Currie agreed retirement postponement should be a “short-term step” especially considering the threat of climate change and that MISO “should demonstrate an openness” to new technologies. “I think our posture has to be one that we don’t sound like we’re counting on delays.”
Ramey added that MISO is sitting on 55 GW of projects with approved interconnection agreements but that remain unfinished, stalled largely by lurching supply chains.
Tyler Huebner, formerly of the Wisconsin Public Service Commission and now with Google, said load growth from computing and manufacturing presents the U.S. with an opportunity to “reinforce” its reputation for ingenuity and intrepidness.
Huebner said Google is working with MISO members to identify the most appropriate locations to site facilities and is working on creative solutions to unlock new capacity.
“We strive to be good grid citizens,” he said.
MISO and its directors are set to discuss the footprint’s load growth trajectory through 2030 and the changing resource portfolio at a nonpublic MISO Board Strategic Planning Session near Seattle on Oct. 28.
Southern California Edison Retiree Poised to Join Board
MISO members will vote on whether to install two familiar faces alongside a retired Southern California Edison executive to their board of directors next year.
MISO announced that membership next week can begin casting votes of support for former Southern California Edison senior vice president Erik Takayesu and current board members Nancy Lange and Mark Johnson. Electronic voting will open Sept. 26 and run through Nov. 1.
Erik Takayesu during his time at Southern California Edison | Southern California Edison
Lange is running for a third and final term. Johnson, on the other hand, is seeking a fourth, three-year term that is possible through a waiver that allows him to exceed MISO’s usual three-term limit.
At a Sept. 19 board meeting, MISO Director Robert Lurie said MISO’s Nominating Committee this year paid particular attention to maintaining board expertise while introducing fresh perspectives. He said board members don’t use the waiver lightly and noted the board is set to experience “significant turnover,” with five directors reaching their term limits within two years. (See Extensions Likely for MISO’s Term-limited Board Members.)
Lurie said the use of a waiver for one board member will provide some “continuity in a fast-changing world.”
“MISO has several initiatives in flight, such as the LRTP, that are multiyear in nature,” he added.
Johnson and Currie both expressed a willingness to stand for an additional term through a waiver of MISO’s usual term limits. Ultimately, MISO’s Nominating Committee advanced only Johnson for a waiver.
MISO considered 23 candidates found by search firm Russell Reynolds and ultimately interviewed eight candidates in person. Lurie said several candidates were equipped with system planning experience.
MISO’s board elections require candidates to earn a majority of votes in support among membership. MISO members can vote for, against or abstain from selecting any of the candidates. The elections require a minimum 25% participation rate among MISO’s approximately 140 voting-eligible members to achieve quorum. MISO will use Votenet Solutions to conduct its membership vote of the candidates.
The board, meanwhile, agreed to raise the base retainer for board members to $200,000 annually.
MISO Budget to Top $400M in ’25
MISO’s budget next year likely will climb to $403.7 million, a 7.7% increase from 2024, MISO members heard.
The proposed budget includes $370.6 million in base operating expenses and $39.8 million reserved for capital expenditures, with the total increase partially offset by interest income.
MISO plans to increase its current $0.47/MWh member rate to $0.51/MWh in 2025.
At a Sept. 18 Advisory Committee meeting, CFO Melissa Brown said lately there has been “a lot more volatility” in MISO’s financials.
Brown said the labor market remains tight, and MISO still has a higher employee vacancy rate than it would like at about 6%.
Brown said calls with other RTOs’ CFOs shows that FERC’s recent transmission planning order is sending other grid operators into a hiring spree. She said she fears some of MISO’s planning staff will be “poached.”
“We’re trying to do all we can to keep our existing system planning folks,” she said.
Dave Burnham of Eversource Energy, representing the New England transmission owners (NETOs), discussed updates to the guidelines for asset condition project presentations at the ISO-NE Planning Advisory Committee on Sept. 18.
The New England states have been pressuring the TOs for greater oversight and transparency into the asset condition project planning process as the costs associated with maintaining the region’s transmission infrastructure have ballooned in recent years. (See New England States Raise Alarm on Eversource Asset Condition Project.)
The states argue the review process at the PAC is insufficient, as the PAC lacks any authority to approve expenditures, which is under FERC’s jurisdiction. The states have discussed the possibility of establishing an independent transmission monitor to oversee transmission spending in the region.
In response to the states’ concerns, the NETOs have proposed and implemented changes to standardize presentations to the PAC, increase transparency into overall asset condition spending and solicit stakeholder feedback on their plans.
Burnham presented updates to the new asset condition process guidelines regarding PAC presentations and the standardization of asset grading.
Going forward, he said project presentations will “discuss any overlap between the proposed project and needs identified in recent ISO-NE studies.”
“This change responds to several stakeholders’ requests for information on correlation of asset condition needs with regional planning study efforts,” Burnham said.
He also discussed an update to the NETOs’ asset condition project database, which was published at the end of August.
The database includes cost estimates on planned, proposed and under-construction projects, as well as preliminary information on under-development projects. Projects expected to come in-service this year are projected to cost $903 million, while the projection increases to $1.6 billion for 2025 and $1.59 billion for 2026.
Asset Condition Project Presentations
National Grid presented a project to address structural damage and deterioration on a 345-kV line in central Massachusetts. The company proposes to replace 19 wooden structures with steel structures, repair insulators on three structures, and conduct “minor maintenance” on 10 structures. This preferred solution is projected to cost $19.4 million, with an in-service date of mid-2025.
Eversource detailed its plans to replace 12 circuit breakers across two substations in New Hampshire, with an expected cost of $25.7 million. The company will replace breakers that use air compression systems, which it said pose “serious reliability risks.” Eversource said it’s ultimately aiming to replace all 127 of these breakers across New England and is prioritizing breakers at substations that have experienced frequent issues.
FERC has accepted SPP tariff revisions that allow make-whole payments for incremental energy costs affected by incremental energy offer caps under Order 831, regardless of the resource’s reason for commitment.
The commission said in a Sept. 19 order that the revisions provide an opportunity for cost recovery, ensuring the resources have an opportunity to recover their incremental energy costs, and an incentive to provide accurate operating parameters and to follow dispatch instructions during Order 831 conditions (ER24-2570).
The revisions are effective Oct. 16.
FERC’s Order 831 revised regulations to address incremental energy offer caps by requiring each commission-jurisdictional grid operator to: cap incremental energy offers at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer; and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LMPs.
SPP uses energy offers between $1,000 and $2,000/MWh to set the LMP, but its Market Monitoring Unit must verify the offers in advance. The MMU verifies whether energy offers above $1,000/MWh reasonably reflect the resource’s actual or expected costs prior to calculating LMPs.
The Monitor told FERC it supported SPP’s proposal, contending there are gaps in the make-whole payment construct that could impede generator owners from receiving full reimbursements under Order 831. It said the gaps could incentivize generators to reduce their financial risks, which could harm the market during extreme conditions.
FERC has dismissed a complaint the Virginia Municipal Electric Association (VMEA) filed against Dominion Energy’s Virginia Electric Power Co. (VEPCO) alleging the utility overcharged its members $2.8 million (EL24-99).
The commission declined to assert primary jurisdiction over the dispute, which it can do at its own discretion.
VMEA is a wholesale customer of Dominion’s utility, and it argued the improper charges were related to the Regional Greenhouse Gas Initiative. VMEA has a full requirements electric service contract with VEPCO, with includes charges based on a formula rate that includes the Uniform System of Accounts, Account 509, as an input.
VEPCO exceeded the RGGI cap in 2021 and 2022, requiring it to spend $137.7 million and $123.5 million in emissions allowances. The utility recovered $84.2 million of that under a rider the State Corporation Commission (SCC) approved.
The rest of the money, $177.1 million, initially was supposed to be recovered in VEPCO’s 2023 biennial rate review, but VMEA said the utility told state regulators that amount would be “deemed recovered” and would not be recovered in future rates.
VMEA claimed the $177.1 million should not have been included in Account 509. It was, and that led to the claim of being overcharged $2.8 million. The association wanted FERC to order Dominion to implement its formula rate without those charges in the account.
Virginia Power told FERC the SCC never disallowed recovery of the RGGI costs, and they were properly included in the rates charged to its retail customers and wholesale customers like VMEA.
The utility initially recovered RGGI costs through the rider, but it got rid of that once Gov. Glenn Youngkin (R) decided to withdraw from the multistate carbon market that had been entered into under his predecessors.
The SCC allowed VEPCO to recover the $177.1 million in its base generation rates in a June 2022 ruling, the utility told FERC. Its deal with VMEA also allows the utility to recover RGGI costs related to its service.
In declining jurisdiction over the dispute, FERC said it did not have expertise compared to the SCC or a state court to adjudicate the dispute. The issue also does not require any uniformity of interpretation for FERC because the facts are unique to the dispute and the complaint also does not raise any broader policy issues relevant to FERC’s jurisdiction.
“Resolution of this matter does not require the commission to interpret its accounting rules and regulations; rather, the dispute concerns the factual issues related to the specific terms of the agreement and the SCC’s decisions in a series of retail ratemaking orders and proceedings,” FERC said Sept. 19.
Commissioner Mark Christie, who chaired the SCC before taking his position at FERC in January 2021, did not participate in the case.
INDIANAPOLIS — MISO said it managed a milder summer overall compared to previous years, though it weathered two hurricanes and escalated into emergency warnings during a heat wave.
MISO served its summertime peak of 122 GW on Aug. 26, using two maximum generation warnings as the Midwest baked under a prolonged heat wave. (See Late August Heat Wave Delivers 122-GW MISO Summer Peak.) Otherwise, summer brought an 85-GW average load, closely following the average load of the three previous summers.
MISO’s average $28/MWh real-time price throughout the season tracked cheap, $2/MMBtu coal and gas prices. The RTO experienced about 31 GW of daily generation outages and derates, lower than in previous years.
At a Sept. 17 Markets Committee of the MISO Board of Directors, Independent Market Monitor David Patton said MISO’s summer peak would have been about 1.8 GW higher without voluntary demand response in the footprint.
“It’s hard to believe it’s been a while since we’ve been here, about three years,” Executive Director of System Operations Jessica Lucas said about delivering a hurricane operations post mortem. She said MISO prepared for an above-normal hurricane season, but so far, storms have been scarce.
Lucas said the Category 1 Beryl nevertheless caused the loss of 73 MISO-operated lines and 250,000 customer outages, a “surprising” number for a “low-intensity” storm.
MISO reported all but one of the lines leading to a Southeast Texas load pocket knocked out of commission. Eventually, the remaining in-service line — a tie line with SPP — went down as well July 8. Prior to the final outage, MISO noticed more generation available in the load pocket than load to serve, leading it to direct all but one generator offline. MISO kept flows on the line at essentially zero to limit potential customer impacts. MISO was prescient to do so, Lucas said, because that remaining line eventually went out of service.
Lucas said she had the “privilege” of being in MISO’s Little Rock, Ark., control room during the night to see firsthand how MISO, SPP and Entergy coordinated to resync the area to the bulk electric system.
“Operating an island for over eight hours is quite a trick. One of my colleagues said it’s like spinning a plate on a needle,” Vice President of Operations Renuka Chatterjee said.
MISO Director Trip Doggett said the feat was the result of “heroic effort.”
“I thought MISO did an amazing job of managing reliability during this event,” Patton said. However, Patton added that southeastern Texas “by far” experiences the most load shedding in MISO.
Patton suggested that MISO “take a hard look at its capacity zones” and consider splitting up MISO’s Zone 9, which contains Louisiana and southeastern Texas. He said the large zone and Louisiana’s capacity-sufficient status mask the fact that southeastern Texas needs resources.
“It prevents the market from signaling that MISO needs to build more generation in this area,” Patton said of the size of the zone.
MISO South’s second hurricane over summer proved more uneventful, Lucas said.
MISO declared conservative operations Sept. 10-13 for its South region as Hurricane Francine made landfall in Terrebonne Parish on Sept. 11 with Category 2 force. At the time, Entergy reported upward of 300,000 customer outages. By Sept. 16, Entergy reported it restored nearly all customers in Louisiana and Mississippi.
“There was not nearly as much excitement as Beryl caused,” Lucas said.
Lucas also noted operators navigated a “wind drought” lasting 11 hours July 21 and eight hours July 22 among its 31-GW wind fleet.
MISO defines wind droughts as periods during which wind output dies down to 500 MW or less for five or more hours. MISO said it has experienced 11 such events since 2020.
“As more weather-dependent resources are added to the portfolio, managing long-term, multiday resource droughts will be a challenge,” Lucas said.
IMM Demands Tougher Demand Response Requirements
Despite summer 2024’s lack of emergencies, Patton used his time slot for a summertime review to ask MISO to “beef up” testing to make sure load-modifying resources can deliver what they promise.
“So much of what we pay for demand response resources has turned out to be manipulative, or not useful to the system,” Patton said.
Patton said a review of MISO’s demand response showed that up to 25% of DR resources submit “mock tests” for their accreditation in lieu of real testing, which presents opportunities for fraudulent data submissions.
Patton said the review also uncovered one commercial retail end-use customer signed up with multiple market participants for the same load and some “unconsummated contracts with critical information redacted that prevent MISO verifying the DR amount or validity.”
Patton also said MISO should stop allowing load-modifying resources to cross-register as both capacity resources and emergency demand response. He said resources should commit to selling one or other, or better yet, MISO should eliminate its emergency demand response program. He pointed out MISO never actually has called on emergency demand response.
Patton’s suggestions come after multiple demand response resources in MISO have been disciplined for deceptive behavior.
Over the past two years, FERC has caught three companies manipulating MISO’s demand response market and collecting unwarranted payments. The commission found that an air separation facility in Indiana accepted payments for fictitious load reductions, an Arkansas steel mill made phony use reductions spanning years, and that an obscure, Texas-based LLC formed to sell in-car ketchup holders fraudulently enrolled customers and made bogus DR offers in three capacity auctions. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.)
