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November 14, 2024

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OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029

[EDITOR’S NOTE: A previous version of this article used the wrong figure for the bottom of the range of expected resource adequacy in summer 2025 in the first sentence (“a potential 1-GW capacity deficit”); this error was also in the excerpt for the article. The survey found that MISO could be short by as much as 2.7 GW.]

A relatively low turnout of constructed capacity in recent years could continue and deepen a potential 2.7-GW capacity deficit in summer 2025 to more than 14 GW by summer 2029, MISO and the Organization of MISO States revealed in their five-year resource adequacy projection.

According to the pair’s 11th annual joint survey, the footprint could either enjoy a 1-GW capacity surplus or contend with a nearly 3-GW deficit by next summer. Much depends on how quickly developers can overcome obstacles to get new resources into commercial operation.

This year’s survey assumed MISO will realize only about 2.3 GW/year in accredited capacity from new builds and did not designate projects with signed generator interconnection agreements as a foregone conclusion in committed capacity totals. The survey also didn’t account for the size of MISO’s record-breaking 300-GW interconnection queue and used a 9.2 to 9.6% planning reserve margin requirement over the next five years.

At the 2.3-GW/year rate — which is the historical average of what developers were able to connect in the past three years — a 5-GW capacity shortfall in planning year 2026/27 widens to 7.4 GW by 2027/28 and nearly 12 GW by 2028/29. Last year’s survey anticipated a 9.5-GW shortfall by the 2028/29 planning year. (See OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028.)

This year’s lower rate of assumed capacity additions spurred debate between MISO staff and stakeholders about what developers realistically can accomplish. That stalled the announcement of the survey results by a week.

During a June 20 teleconference to discuss the results, David Schoon, MISO resource adequacy engineer, said the RTO reflected a “new paradigm” from its interconnection queue in the survey. He said MISO’s current 50-GW backlog of unfinished generation that’s been approved to connect to the system but still is waiting in the wings influenced the survey’s new method of evaluating capacity additions.

Schoon said MISO felt it needed to reflect the stubborn trends from the “COVID slowdown, such as continuing supply chain bottlenecks, commercial uncertainty and permitting and labor delays,” despite what interconnection customers claim will be brought online.

“We’ve got to get out of that guessing game,” Schoon said of the queue’s annual yields. He said it’s not realistic to assume developers can bring an “explosion” of resources online in a single year.

However, Schoon said MISO and OMS also contemplated that circumstances mend over time, and the footprint experiences an influx of skilled labor, a less fraught supply chain, expedited permitting and commercial viability of new technologies. In that alternative projection, MISO might connect more than double its three-year historical rate, at a little more than 6 GW annually.

At 6.1 GW/year, MISO could enjoy a 4.6-GW surplus by summer 2029.

However, MISO added a caveat that large, spot-load additions could balloon over the next five years and threaten a more than 30-GW shortfall under the 2.3-GW/year scenario and a nearly 10-GW shortfall even under the 6.1-GW/year rate.

“The situation is changing very rapidly around us,” said Senior Director of Resource Adequacy Durgesh Manjure, referring to generation retirements and a resurgence in load growth through new data centers.

“Immediate actions are needed to expedite the addition of new capacity, coordinate resources for new load additions and potentially moderate the pace of resource retirements,” Schoon said.

Josh Byrnes, OMS president and member of the Iowa Utilities Board, said RTO members’ actions over the next year will matter a great deal. “We need to quickly move to make sure that new load doesn’t outpace generation additions,” he said.

Byrnes said the RTO should focus on ushering new capacity through its interconnection queue expeditiously and “use the expansive MISO footprint to the fullest” through regional transfers.

In a press release accompanying survey results, Byrnes stressed that as the region faces “tightening capacity reserve margins compounded with rapid and large load additions, it is imperative for everyone from developers (new load and generation), economic development authorities, utilities, regulators, MISO and other stakeholders to work in close coordination.”

WEC Energy Group’s Chris Plante asked if MISO has considered that load-serving entities with planned data centers in their territories will take pains to ensure they can cover the large load additions with new capacity or purchases.

MISO’s Scott Wright said OMS and the RTO deliberated on the steps utilities and local governments will take to spur economic development.

“But we’ve also noted that laying it out this way highlights the fact that … a lot of these are un-resourced loads,” Wright said.

Michigan Public Power Agency’s Tom Weeks asked if MISO or its consultants mulled quantum computing emerging in time for the new decade, which could make data center energy consumption “plummet by orders of magnitude.”

Schoon said such breakthroughs weren’t included as possibilities in survey results.

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Group Claims Powerex Backing Markets+ to Benefit from Divided West

A new study commissioned by Renewable Northwest (RNW) adds a contentious new wrinkle to the debate about the potential impact of market seams if the West ends up divided between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.

The study, conducted by Grid Strategies, comes about five months after release of a report from the Western Power Trading Forum and Public Generating Pool that cautioned that seams between Western day-ahead markets would create a different set of challenges from those seen at the boundaries between the full RTOs in the Eastern Interconnection. (See Western Market Seams Issues to Differ from East, Study Finds.)

The Grid Strategies study partly expands on that theme, finding that effective “market configuration” — meaning a market based on the widest footprint possible — outweighs the importance of market design. It also warns that lessons from the Eastern Interconnection show that market seams there continue to be a “persistent drag on efficiency” despite the mechanisms MISO, PJM and SPP have implemented to mitigate their impact.

The study also delves into the specific challenges a two-market scenario could pose in the Pacific Northwest, where neighboring and closely interconnected balancing authority areas — such as those operated by the Bonneville Power Administration and PacifiCorp — fall into separate markets, creating a winding and complicated boundary.

BPA, which controls about 75% of transmission in the Northwest, has made it clear its decision on a day-ahead market will not be driven by concerns about seams and has argued such issues can be resolved by seams agreements. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.)

The Grid Strategies study finds that “while experience in other markets support BPA’s argument that a seams agreement is necessary, experience also shows that seams agreements do not reduce barriers to transacting across market seams and will not address the detrimental impact of market seams on consumers.”

‘Hard to Achieve’

But the most controversial aspect of the new study is the contention that Vancouver, British Columbia-based energy marketer Powerex has backed the development of Markets+ because it stands to make more money trading in a divided West than in a single market with no seams.

That’s an assertion other Western electricity sector stakeholders have shared with RTO Insider but have been reluctant to put on the record.

“Well, to the detriment of my dreams to retire in Canada, I decided to go on the record,” RNW Executive Director Nicole Hughes joked in an email to RTO Insider. RNW is a renewable energy trade group that long has advocated for the development of a single organized market in the West and is a key supporter of CAISO’s EDAM.

Hughes was referring to a June 14 opinion piece she wrote for the Seattle-based publication Clearing Up.

The op-ed draws on Chapter 9 of the Grid Strategies study, which is headed “Good Configuration is Hard to Achieve Because Some Parties Benefit from Bad Configuration and Inefficient Seams.”

The chapter explains that BPA and Powerex control the largest amount of power supply and transmission in the Pacific Northwest, the latter being “the exclusive marketer of BC Hydro capability in the U.S., holding substantial hydro generation, storage and transmission rights, and is a major energy supplier to the Northwest.”

Powerex’s “mission” in participating in the U.S. market is “to maximize profits” on behalf of British Columbia’s ratepayers, the study says.

“As the exclusive marketer for BC Hydro, Powerex reports that electricity ‘trade provides economic and environmental benefits for British Columbia. All income generated by Powerex is returned to BC Hydro, which helps the utility keep electricity rates amongst the lowest in North America,’” it says, citing Powerex’s description of itself in the “About Us” section of its corporate website.

Last year, the Western Markets Exploratory Group (WMEG) completed a series of studies, conducted by Energy+Environmental Economics (E3), to assess the benefits that would accrue to various electricity market participants in the West under a range of market footprint scenarios.

Grid Strategies cites wording in the WMEG study for Powerex, which found that in a scenario where Northwest utilities join EDAM, Powerex “expects that its most attractive market opportunities would be forward sales,” prompting the company to limit the hourly flexibility of its hydroelectric exports.

But in a situation where Northwest utilities join Markets+, E3 determined Powerex “expects that its most attractive market opportunities will be hourly optimized transactions” and that it would offer the market its full hourly flexibility.

“E3 estimates that the incremental regionwide cost increase attributable to Powerex’s withholding hourly flexibility in these scenarios is approximately $7 million,” Grid Strategies says. “This example shows how positional power and control of transmission can have significant financial consequences for consumers in the Northwest.”

As the competition between EDAM and Markets+ plays out, SPP has found its strongest support among some entities in the Northwest, including BPA and Powerex, and among Arizona utilities Arizona Public Service, Salt River Project and Tucson Electric Power. But other major players in the Northwest, including PacifiCorp, Portland General Electric and Idaho Power, have signaled their intent to join EDAM, with Seattle City Light likely to follow.

Transmission links between the Northwest and Southwest are limited, and the Grid Strategies study notes that “control of key transmission capacity rights connecting the Northwest to the Southwest is highly concentrated, with a meaningful portion controlled by Powerex, who as a power marketer has an objective of maximizing profits, rather than minimizing consumer costs as do load-serving transmission capacity owners.”

“A pivotal supplier exercising market power can manipulate prices, benefiting itself to the detriment of load-serving entities and consumers,” the study continues. “It is very difficult to mitigate this market power in a two-market setting with no centralized oversight of the broader region. If the seams were more efficiently managed internally within a single market, this would be less likely to occur.”

Powerex Points to Governance, Design

In her op-ed, Hughes points out Powerex controls about 20% of transmission capacity rights on the California-Oregon Intertie, a key link between the Northwest and CAISO. She says direct trade with the Desert Southwest would allow Powerex to avoid paying to wheel power through the CAISO system.

“Powerex states that the solution to congestion rents wheeling through CAISO is to build more transmission to the Desert Southwest,” Hughes wrote. “More interregional transmission connectivity between the two regions would definitely benefit customers West-wide. However, several utilities serving major load centers are committed to continuing to operate in CAISO’s WEIM [Western Energy Imbalance Market] and have committed to expanding their commitment by joining its Extended Day-Ahead Market, while BPA is leaning toward leaving the WEIM and joining Markets+.”

Hughes also asserts the WMEG study indicates BPA would benefit from increased transmission revenues in a divided day-ahead market scenario while the rest of the region would see rising transmission costs.

Reached for comment, BPA spokesperson Doug Johnson said the federal power marketing administration was unprepared to respond to the Grid Strategies study or Hughes’ op-ed.

In an email to RTO Insider, Jeff Spires, director of power at Powerex, said that while “attention to seams is important,” the intent of the study “appears to be to distract from the essential governance and market design elements that differentiate the two day-ahead market options.”

“Powerex is just one of numerous entities participating in the development of Markets+, who collectively seek an organized market that provides independent and inclusive governance, an impartial market operator and a market design that achieves competitive market outcomes while balancing the interests of a broad array of participants,” Spires wrote.

Takeaways

The Grid Strategies study concludes with a handful of “key takeaways.” Chief among them is the assumption FERC is “unlikely to mandate good configuration and does not have a template for effective, efficient and equitable seams coordination,” leaving it to Western utilities and regulators “to evaluate customer impacts and make the best decisions for ratepayers” when it comes to day-ahead market decisions.

Another point is that attempts to address market inefficiencies caused by seams in the East have been “largely unsuccessful.”

“Transactions between markets are far below efficient levels, resulting in higher consumer costs,” the study says.

Yet another takeaway has to do with the access issues that would stem from a two-market configuration in the Northwest because of the region’s “heavy reliance” on BPA’s transmission.

“If market seams are developed between the major load centers in the region and the generation and transmission needed to serve these load centers, costs to consumers will increase, and efforts to bring new clean energy generation to load will be hindered,” the report says. “Particular attention should be paid to avoiding development of these seams today, and ample opportunity currently exists to develop a market [that] will minimize negative impacts to customers.”

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ISO-NE PAC Briefs: June 20, 2024

ISO-NE announced its plans to increase the transfer limits of three interfaces in Maine at the Planning Advisory Committee’s meeting June 20. 

The RTO is planning to up the limits of the Orrington-South interface from 1,325 MW to 1,650 MW, the Surowiec-South interface from 1,500 to 1,800 MW and the Maine-New Hampshire interface from 1,900 to 2,000 MW.  

Dan Schwarting of ISO-NE said the new limits will be incorporated into day-to-day operations, including the wholesale energy markets, in late June or July. 

“Impacts on capacity transfer limits, and any resulting implications for Forward Capacity Market-related activities, will be discussed in future meetings,” Schwarting said, adding that the new limits will also apply to future planning efforts. 

Asset-condition Projects

New England transmission owners discussed proposals for several major new investments to address degrading transmission infrastructure. 

Zach Logan of Avangrid presented a proposal by Maine Electric Power Co. to replace aging poles on a 345-kV transmission line in the eastern part of the state. While the company has determined “the overall condition of the lines are good to fair, and there are no immediate needs for a complete line rebuild,” most of the poles date back to 1969 and are expected to deteriorate at an increasing rate as they pass 60 years of age. 

The company is proposing to replace structures at a rate of about 40 to 50 per year through 2038, at a total estimated cost of $344 million. 

Chris Soderman of Eversource Energy presented a follow-up to the company’s February presentation of a proposed rebuild of a 115-kV line in New Hampshire, projected to cost about $361 million with an in-service date in the fourth quarter of 2026. 

ISO-NE Maine interfaces | ISO-NE

Responding to stakeholder feedback submitted after the February presentation, Eversource analyzed the costs of a partial line rebuild compared to the full rebuild that is currently planned. The company found that partly rebuilding the line would save money in the near term but ultimately increase overall project costs to about $437 million when accounting for subsequent projects that would be needed to replace other aging structures. 

“The bulk of these structures are already 40 years old” and need to be replaced “in a relatively short time frame,” Soderman said. 

Soderman also presented a proposed $5.5 million project to replace 19 structures on a 115-kV line between Maine and New Hampshire, projected to be complete by the end of the year. 

John Babu of Eversource announced a $5 million project to replace eight relays on a 115-kV substation in Harwinton, Conn. Eversource said the manufacturers are no longer producing replacement parts for the relays. 

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NERC State of Reliability Report Notes Progress, Challenges in 2023

Releasing its annual State of Reliability report this week, NERC sounded a note of confidence in the “overall resilience” of the North American electric grid. However, the ERO also observed that the grid continued to face growing challenges over the last year that will require collaboration of multiple stakeholders to address. 

The report reviews the performance of the electric grid over the past year in order to inform regulators, policymakers and stakeholders about the most significant reliability risks, and to describe the ERO Enterprise’s actions in response to those risks. This year’s report comprises an overview, which is a high-level summary of NERC’s findings, along with a more detailed technical assessment. 

With “relatively mild weather [and] enhanced protection measures” across most of the continent, system operators faced fewer stressors during the grid’s peak winter and summer months, John Moura, NERC’s director of reliability assessment and performance analysis, said in a statement. The ERO found that utilities provided 4.69 billion GWh last year, higher than any of the past five years, which was provided by 5,915 conventional generating units of at least 20 MW and delivered by more than 528,000 miles of transmission lines. 

The grid last year also experienced no non-weather-related Category 3, 4 or 5 events; no hours of operator-initiated firm load shedding associated with a Level 3 energy emergency alert; and no unserved energy associated with a Level 3 EEA. By comparison, in last year’s State of Reliability report, NERC reported 56.5 hours of firm load shedding and 96.2 GWh of unserved energy associated with Level 3 EEAs. 

In 2023, the North American electric grid experienced a weighted equivalent forced outage rate of 7.8% averaged across all fuel types, the third highest on record for the past 10 years. | NERC

NERC said one reason the grid performed better last year was that grid operators responded quickly to the kind of severe weather events that have tested the grid in recent years. According to the National Oceanic and Atmospheric Administration, the U.S. experienced 28 “billion-dollar events” last year, defined as weather or climate disaster events that caused damages of at least $1 billion (adjusted for inflation) — well over the five-year average of 20.4 events. 

The ERO acknowledged that the year’s biggest severe weather event was not captured in NOAA’s data — namely, the wildfires in Canada that burned more than 71,000 square miles of forest areas between June 20 and July 26, the record for the country. NERC’s report highlighted the impacts to Quebec, where the largest number of fires occurred. One hundred and one small outage events were reported as a result of the fires; however, these were mostly short, with an average duration of 1.2 hours, and “generally not overlapping.” 

“Transmission metrics were disproportionately impacted by the short-duration outages associated with these wildfires, specifically within the Quebec Interconnection,” NERC said in the report. “However, due to operator actions, as well as the fires’ varied timing and geographical locations, the actual impact on [grid] reliability was minimal.” 

While the ERO was upbeat about the grid’s resilience in the face of extreme weather, it did note that forced-outage rates among conventional and wind generation remained at “historically high levels [in 2023], exceeding rates for all years prior to 2021.” In a media webinar, Jack Norris, an engineer with NERC’s Performance Analysis division, pointed out that the grid experienced a 7.8% weighted equivalent forced-outage rate (WEFOR) in 2023, the third-highest on record for the last 10 years after 2021 and 2022. 

Coal units recorded the highest WEFOR at 12%; this is below the previous two years but still higher than the average of 10% between 2014 and 2022, Norris said. Hydropower also experienced an “unusually high outage rate” of about 7%, he added, which put it above the 10-year average along with natural gas. Nuclear power was the only outage type with a below-average WEFOR, with just under 2%. 

Norris said the outage rates for coal generation are consistent with “increasing WEFOR rates for coal that we’ve been seeing over the last several years and [align] with industry statements [about] reduced maintenance on older coal units as they’re being phased out.” He also noted that utilities have had to cycle coal units on and off more often in recent years “to accommodate variable energy resources,” which strains these units, a likely cause of increased outages. 

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Report Shows Wide Range of Data Center Demand Scenarios for Virginia

Growing demand from Northern Virginia’s Data Center Alley could outpace the power industry’s ability to keep up, according to a report released June 20 by Aurora Energy Research.

PJM’s latest 2024 forecast shows 11 GW of demand from new data centers in Northern Virginia alone by 2030, which would represent 40% of Virginia’s peak demand. In the report “Impacts of Virginia data center demand growth on the power system,” Aurora says data center demand could reach as much as 16 GW by the end of the decade.

New supply would be needed to meet such demand, which the report said could drive up to 15 GW of new natural gas capacity because intermittent renewables alone would not provide the reliability that PJM market rules require. Dispatchable resources such as natural gas or battery storage would be needed to reliably serve new data center load, according to Aurora.

The need for new supply could affect data center demand growth, with the report noting new plants take years to get through PJM’s interconnection process and connect to the grid. Relatively high power prices in Virginia and increasing geographic flexibility from data centers could drive them to be built elsewhere.

“Adding the 10 to 15 GW of firm generation capacity needed to supply these data centers and keep the lights on in Virginia will not be easy,” Aurora’s PJM Research Lead Zachary Edelen said in a statement. “It can take three to four years for the transmission organization just to greenlight a new generator, and market prices are currently too low for developers to build the kind of capacity required.”

Renewable capacity grows significantly in PJM under all of Aurora’s scenarios, which forecast a minimum of 40 GW of new nameplate capacity in the region. But renewables are credited well short of their nameplate capacity in PJM’s capacity market and that along with data centers’ need for steady power supplies lead to more need for natural gas plants and batteries.

“As a result, our analyses consistently show that data centers bolster the business case for natural gas generators, meaning state and federal governments will need to do more if they want to decarbonize,” Edelen said.

Northern Virginia’s Data Center Alley is home to 25% of national data center load. Its 4 GW of demand beat that of every country except the U.S. itself and China. Nearly 300 data center facilities are in Northern Virginia, with a cluster around Data Center Alley in Ashburn, according to the report.

Growth was so fast there that Dominion Energy had to pause new connections in 2022 to avoid spiking congestion. Now the utility is implementing grid updates to deal with the bottleneck. Dominion expects 20 GW of new load and plans to invest nearly $5 billion in transmission to deal with that, according to the report.

Data centers are considering behind-the-meter generation as they work to improve efficiency in their operations in the face of high electricity costs in Northern Virginia, according to the report, which also noted the centers increasingly can locate elsewhere as internet connections improve.

Aurora’s demand forecasts range from 10 to 37 GW by 2040; a 24-GW growth scenario is in line with PJM’s load forecast.

Dominion forecasts 11 GW of additional capacity obligations for its footprint by 2030 and plans to buy and import about 59% of that from around PJM. Its transmission spending plans will help enable that.

The RTO will need more capacity to meet the Virginia data center demand because of planned retirements. Aurora forecasts a 12-GW shortfall in “unforced capacity,” which would take 15 GW of new gas plants, or 20 GW of batteries if they hold four hours of charge.

The higher demand is expected to help push up power prices, with the forecast closest to PJM’s adding $3/MWh to the average, but the extreme case of 37 GW by 2040 would add $16/MWh.

Data centers building their own generation could put a cap on how high their new demand drives wholesale prices, the report noted. A combined cycle gas turbine would make sense for big data centers if the generator’s capacity factor is high enough, which would be the case at average data centers that have a load factor of 88%, according to the report.

“A strategy of building one’s own behind-the-meter generation carries risks, including necessitating a long generator lifetime to realize benefits, policy risk (from potential decarbonization rules), outage risk and potential local pushback from neighboring residents,” Aurora said in the report.

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CAISO Kicks off Stakeholder Process for Pathways Initiative

CAISO on June 18 kicked off the West-Wide Governance Pathways Initiative stakeholder process required to shift the ISO’s governance structure to an independent entity within the Extended Day-Ahead Market (EDAM).  

During a conference call, members of the initiative’s Launch Committee presented Step 1 of the “stepwise” approach, which would elevate the “joint” authority over both the EDAM and the Western Energy Imbalance Market that the latter’s Governing Body shares with CAISO’s Board of Governors to “primary” authority. This means the body would be the first to vote on tariff change proposals for both markets. 

The moves are meant to quell fears about the ISO’s state-run governance structure. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.) California’s governor appoints members of the ISO’s board, on which the State Senate votes to confirm. 

The stepwise approach was outlined in a straw proposal released June 5. 

“We’re looking to create a structure that can enable the largest footprint possible and include California,” said Kathleen Staks, WWGPI co-chair and director of Western Freedom. “We ultimately want this entity to be able to evolve and add market services up to and including a full regional transmission organization.”  

The first round of stakeholder feedback led Launch Committee members to highlight a focus on respecting state and local authority in the initiative, “ensuring we are creating a structure that respects each individual state’s ability to set and enforce its own energy policies,” Staks said. “We are not looking to create something that is going to enable one state to force its policies on another state and vice versa.” 

Over the summer, committee members and stakeholders will be working on a proposal for Step 2, which would establish a “regional organization” as a legal entity and, after passage of required California legislation, transfer the Governing Body’s primary authority to “sole” authority. 

Stakeholder Comments

Some stakeholders expressed concern that the initiative still doesn’t achieve the level of independence needed to quell concerns surrounding CAISO’s governance structure. 

“We appreciate steps forward with the Step 1 proposal to extend [Federal Power Act Section] 205 filing rights and primary authority to the WEIM Governing Body,” said Doug Marker, intergovernmental affairs specialist at Bonneville Power Administration. “But at the same time, as we’ve said, we don’t believe that it by itself achieved the level of independence from any one state’s authority that’s necessary for a regional market. 

“What we’re concerned about is that transition to primary authority could lead to the CAISO Board of Governors being disconnected from WEIM and EDAM issues and possibly increased conflict between the Board of Governors and the WEIM Governing Body.” 

Marker requested that the committee consider elements that could be added to the proposal that could support continued collaboration between both entities.  

“We have a number of [Governance Review Committee] members … who are aware of the perceived and, I think, real value of the increased collaboration that happened moving to the joint authority model,” responded Spencer Gray, committee members and executive director of the Northwest & Intermountain Power Producers Coalition. “While we didn’t touch on the mechanics of whether the two bodies would continue to be jointly going forward, we certainly didn’t want to preclude that approach.” 

A second stakeholder call is tentatively set for July 23. 

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MISO Readies JTIQ Filings, Hints at More Tx Portfolios with SPP

Two years after announcing its $1.8 billion Joint Targeted Interconnection Queue (JTIQ) transmission portfolio with SPP, MISO is putting final touches on its FERC filings to make it happen.  

During a June 18 teleconference to outline its plan, MISO’s Milica Geissler said the RTO will begin making filings to FERC at the end of July, starting with an addition that chronicles JTIQ procedure for its joint operating agreement with SPP. Subsequent filings on cost allocation, generator interconnection agreements and rate schedules will follow, Geissler said, and may be standalone or combined. All filings concerning JTIQ will seek a common effective date, she added.  

MISO said it will work with its transmission owners to make the later filings. SPP similarly is finalizing JTIQ details. (See SPP Board Adds Final OK to JTIQ Cost Framework.)  

“We’ve been working on this for four years, and we’re finally able to present a full package,” MISO Director of Resource Utilization Andy Witmeier said, referencing the 2020 announcement that MISO and SPP would try a new approach to interregional planning after years of unsuccessful pursuits for transmission prospects.  

MISO counsel Chris Supino said the JTIQ process — which will replace MISO and SPP’s affected-system studies — will allow generation developers to learn their cost responsibility earlier and get projects connected sooner.  

Supino said the first portfolio represents the most “immediate need for beneficial, backbone projects” along the MISO Midwest and SPP seam. He said MISO may focus on MISO South for its next JTIQ portfolio with SPP.  

Witmeier said the first portfolio should dramatically decrease the costs of getting generation online near the seam. He said a recent SPP affected-system study returned $1.4 billion in network upgrades for just 8 GW of projects connecting in MISO. On the other hand, Witmeier said the $1.8 billion JTIQ is expected to enable 28 GW in generation additions.  

MISO and SPP are pursuing a 100% cost allocation to interconnection generation. The two initially planned to use a split entailing 90% to generators and 10% to load, but they abandoned the approach after the Department of Energy announced the portfolio would receive $464.5 million from the department’s Grid Resilience and Innovation Partnership program. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) MISO and SPP’s load will act as a temporary cost backstop for their share of JTIQ costs until enough new generation commits to the lines and picks up the tab for construction.  

Geissler said it’s unlikely that load will have to cover any JTIQ costs permanently because of the sheer numbers of prospective projects in MISO’s and SPP’s interconnection queues. However, construction may begin on the JTIQ projects before they’re fully subscribed. MISO said it will consider JTIQ portfolios fully subscribed when 85% of the megawatts they can enable are spoken for. For the first JTIQ portfolio, that subscription threshold will be a little more than 24 GW in generation projects.  

Witmeier added that MISO load should benefit from lower congestion costs and decreased market-to-market payments once JTIQ projects are built.  

SPP’s interconnection queue boasts 412 projects totaling more than 84 GW; MISO’s interconnection queue could approach 350 GW, if all the 123-GW 2023 class of queue applications are allowed to proceed. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.)  

“The existing system was not designed to handle this level of generation,” Supino said.  

MISO expects to begin accounting for JTIQ projects in its generator interconnection queue study modeling next year, after the RTOs’ boards approve the JTIQ portfolio.  

MISO and SPP plan to study generation projects that may rely on JTIQ projects in clusters. MISO said it will screen projects and move those dependent on JTIQ into a “participation group.” Generation projects will enter a “commitment group” once they close in on generator interconnection agreements and will be assessed a per-megawatt JTIQ charge that is billed directly by either MISO or SPP.  

Sustainable FERC Project attorney Lauren Azar asked if MISO is planning to change JTIQ rules to integrate changes stemming from FERC’s recent show-cause order issued to MISO and three other RTOs. The commission last week put the grid operators on notice that their policies allowing transmission owners the opportunity to provide initial funding for network upgrades may impede interconnection customers’ right to finance the upgrades they pay for. (See FERC Issues Show-cause Order on TO Self-funding in 4 RTOs.)  

“That’s something we’re still evaluating,” Supino said. “We’re still going to have to determine how this impacts it.”  

But Supino said that unlike normal upgrades that transmission owners can elect to self-fund, the JTIQ involves large projects that are prebuilt by transmission owners assigned by MISO or SPP.   

“I’m not certain it’s going to raise the same questions,” Witmeier said. 

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FERC Accepts Results of New England Capacity Auction

FERC accepted the results of ISO-NE’s Forward Capacity Auction 18 on June 18, finding that the auction was run according to the RTO’s tariff and that protests submitted by climate activists were outside the scope of the proceeding (ER24-1290).  

FCA 18, which was held in February and relates to the 2027/28 capacity commitment period (CCP), saw an approximately 40% increase in the cost of capacity relative to the previous auction, along with a rise in renewable resources. (See Prices, Renewables Rise in New England Capacity Auction.) 

The auction likely marks the last auction held prior to the implementation of major changes to ISO-NE’s capacity market.  

The RTO is amid a multiyear process reworking how it calculates resource capacity values, and also is pursuing significant changes that would split the annual CCP into seasons and hold auctions much closer to each CCP. This year, FERC approved a three-year delay of the next capacity auction to give ISO-NE time to develop these changes with the goal of implementing them for FCA 19. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

ISO-NE’s filing of the results spurred opposition from climate activists, who argued the auction was biased in favor of fossil fuel resources. (See Climate Activists Urge FERC to Reject Results of ISO-NE FCA 18.) 

“These results are in violation of ISO-NE’s tariff and mandate to ‘protect the health of the region’s economy and the well-being of its people by ensuring the constant availability of competitively priced wholesale electricity — today and for future generations,’” the group No Coal No Gas wrote in comments signed by more than 4,000 individuals. The group also protested the results of the three prior FCAs.  

“FCA 18’s award of nearly $350 million in forward capacity payments to fossil fuel peaker plants is a clear violation of this mission,” the organization added. “Supporting fossil fuel generators that can only provide electricity by worsening climate change and exacerbating grid instability is dangerous, irresponsible grid management.” 

Echoing its response to the protests of previous FCAs, FERC sided with ISO-NE, ruling that the structural critiques of the auction are outside the scope of the proceeding. (See FERC Accepts Results of ISO-NE FCA 17.)

The commission wrote that the protests “do not bear on the sole question here — namely, whether ISO-NE conducted FCA 18 in accordance with the requirements set forth in its tariff.” 

“Instead, these protests largely challenge the FCM design and raise various challenges related to climate change, fossil fuels, the minimum offer price rule and the Merrimack Generating Station, which are issues that are beyond the scope of the instant proceeding,” FERC said. 

FERC added that the concerns about a conflict between ISO-NE’s mission statement and the capacity market design “are more appropriately raised in the stakeholder process.” 

ISO-NE applauded FERC’s ruling, writing in a statement that “the Forward Capacity Market is and has been open to all resources able to provide capacity to the region, and claims of bias are without merit.” 

“All the new resources clearing in this year’s auction were renewable energy, battery storage or demand-reducing resources,” wrote ISO-NE spokesperson Matt Kakley. “We look forward to continuing to work with stakeholders and the New England states on longer-term changes to the capacity market.” 

Meanwhile, climate activists expressed disappointment with the decision and took issue with the commission’s suggestion that they raise their concerns within the NEPOOL stakeholder process.  

Marla Marcum of No Coal No Gas emphasized that the NEPOOL process is closed to nonmembers and that member groups representing end users have minimal voting power within the organization. 

“Referring us to a body to which we are unlikely to gain access, and which explicitly limits public input and agency, is unfortunately typical of this system — a system designed to prevent meaningful participation,” Marcum said, adding that FERC’s ruling suggests ratepayers “should have no effective way to participate in decisions about the billions of dollars taken from their utility bills every year to manage the grid.” 

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Renewable Development Faces Regulatory Tangle

Two new reports have been published on the profusion of local and state regulations affecting renewable energy development — one attempting to summarize them, the other quantifying the growing number of restrictions they impose. 

“Laws in Order: An Inventory of State Renewable Energy Siting Policies” summarizes the renewable energy siting and permitting policies in the 50 states and Puerto Rico. One of its findings is that the approach to this type of regulation can be difficult to categorize because it varies widely from one state to the next. 

“Opposition to Renewable Energy Facilities in the United States: June 2024 Edition” is an update of similar reports in 2021, 2022 and 2023. This year’s report finds 29% more contested projects nationwide than last year’s, along with 73% more local restrictions and 111% more state-level restrictions. 

List of Laws

“Laws in Order” was prepared by the Regulatory Assistance Project and Clean Air Task Force with support from the Department of Energy, Lawrence Berkeley National Laboratory and Consensus Building Institute. 

The team created an inventory of the siting and permitting policies that pertain to large-scale solar and onshore wind projects and the often-complex, layered mesh of approvals needed before construction can start. 

The report provides a summary of the findings and draws a profile for each state and is accompanied by an interactive map. It also identifies the: 

    • entities within each state or territory that make siting and permitting decisions; 
    • level of government that has the authority to set standards for large-scale renewables siting and construction;  
    • requirements for public involvement;  
    • timelines that exist; and 
    • availability of permitting guides and model ordinances designed to support local decision-making. 

A display of state-level model ordinances available to guide solar and wind power development | Regulatory Assistance Project

Illustrating the highly varied nature of regulatory oversight, the report notes that 12 states give local governments principal jurisdiction, the governments in five states and Puerto Rico hold jurisdictional authority, local and state governments share authority in six states, and oversight can fall to either the state or the local government in 27. 

List of Obstacles

“Opposition to Renewable Energy Facilities” was produced by the Sabin Center for Climate Change Law at Columbia University. 

Without making individual judgments on the hundreds of examples they cite, the authors conclude that as a whole, there is widening local opposition to renewable energy facilities that is a potentially significant barrier to achieving emission-reduction goals. 

The report looked only at restrictions so severe that they have either killed a specific project or could limit or ban development of renewables. It catalogs 395 such restrictions at the local level and 19 at the state level in 41 states. It also identifies 378 renewable projects in 47 states that have encountered significant opposition. 

Alaska was the outlier as the only state with no severe restrictions or significant controversies identified. 

Polices that bear indirectly on renewable energy facilities — such as net metering, renewable energy standards or subsidies — are not included if they do not bear directly on renewables. But the authors note local governments increasingly taking action to oppose the infrastructure needed to support renewable energy facilities, such as transmission and battery storage.

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FERC Order 1920 Sees Wide-ranging Rehearing Requests

FERC has received rehearing requests on Order 1920 ranging from stakeholders who just want to see a few tweaks, to those who prefer the commission trash the entire order and start over.

Many states filed for rehearing on the order, arguing for more authority and flexibility for their efforts to reform transmission planning and cost allocation rules that started before FERC issued its order. (See Order 1920 Rehearing Request from States Seek Bigger Role in Tx Planning.)

The only two RTOs that filed for rehearing also sought flexibility to keep going with the changes they have been working on with stakeholders. PJM seeks to continue with its Long-Term Regional Transmission Planning (LTRTP) process and SPP with its Consolidated Planning Process (CPP).

PJM’s changes would lead to a process where, working with states and other stakeholders, it could come up with scenarios based on evolving concerns such as the changing resource mix and new demand. It was designed to reflect the realities of the RTO’s region, which is “comprised of 14 jurisdictions that have public policy initiatives that are simultaneously overlapping and conflicting — while also taking into consideration the challenges the PJM region is facing as a result of the accelerating energy transition.”

The LTRTP process is meant to deal chiefly with reliability while considering states’ policy requirements in consultation with them. The rule prevents transmission providers from setting up cost allocation methods that separate out reliability, economic and public policies, but PJM said its disparate state membership means it should be exempted from that. The LTRTP process does not align with Order 1920’s requirements perfectly, and some details differ from FERC’s requirements, the RTO said.

“However, PJM believes that the PJM LTRTP process is directionally consistent with the commission’s long-term planning goals, and importantly, the process recognizes PJM’s unique needs and circumstances,” the RTO said.

SPP asked for clarification that it could move forward with a different set of rules around its CPP process.

“The CPP will include a comprehensive long-term assessment that projects supply and demand needs over a 20-year period, incorporating regional and subregional components,” the RTO said. “The CPP will allow for simultaneous planning of transmission, as opposed to the piecemeal approach SPP employs today.”

The new planning process uses a single, common base model for the entire region, it improves data collection, and SPP said it was working on a cost allocation method that would require flexibility from some of Order 1920’s requirements.

The Re-evaluation Requirement

One area transmission owners singled out for review was the requirement that transmission projects be re-evaluated after they’re picked in a regional plan under Order 1920.

It kicks in when projects are delayed long enough to impact reliability, if actual costs significantly exceed estimates, or if some underlying law or policy changes.

The Edison Electric Institute argued that section of the rule was poorly noticed, with FERC pointing to paragraph 248 in the Notice of Proposed Rulemaking. The utility trade group argued that paragraph lacked sufficient detail to count as appropriate notice under the Administrative Procedure Act.

“The onus is on the agency to inform stakeholders that it is considering a proposal put forth in comments; the onus is not on stakeholders to sift through thousands of pages of comments and respond to each one in case the agency should decide to use a particular proposal as the basis for its final rule,” EEI said.

Order 1920 largely takes MISO’s transmission planning process and sets it as the baseline for other regions to implement their own rules around, but a large group of MISO TOs argued that the re-evaluation requirement goes well beyond what they are used to in one key way: The RTO’s “variance analysis” does not require transmission lines to be re-evaluated using new benefits that have been updated since it initially was planned.

The benefit re-evaluation requirement conflicts directly “with the commission’s intended goal of shaping a regulatory environment that facilitates regional transmission development,” the MISO TOs said.

Using new benefits in the updated process creates massive uncertainty for transmission development and basically “requires re-planning every five years,” they added. That increases the risk that transmission will be removed from the plan based on entirely new inputs and assumptions, which can put at risk permits required by other regulators and could implicate projects already under construction.

“Such uncertainty also risks spooking investment in these crucially needed transmission facilities and may delay subsequent portfolios of long-term regional transmission facilities as the resources that would otherwise be used in their development will be used to re-evaluate past portfolios,” the TOs said.

The WIRES Group also told FERC it should reconsider the re-evaluation requirement because it could undermine, by delay or cancellation, the development and timely completion of long-term regional transmission facilities.

Rights of First Refusal

Both WIRES and EEI had the re-imposition of rights of first refusal as a major goal for the order, and FERC did that with projects “right-sized” from the local planning process into the regional planning process, but neither of them brought up the issue in their rehearing filings.

The right-sized ROFR did come under fire from the Electricity Transmission Competition Coalition, the Resale Power Group of Iowa and LS Power Grid.

“Competition in the transmission planning process for the right to develop and construct new transmission facilities reduces costs to consumers and drives efficiencies in project construction,” ETCC said. “The Competition Coalition supports competition and competitive prices to maintain just and reasonable transmission rates, consistent with Order No. 1000’s pro-competition directives.”

Giving incumbent owners a ROFR over transmission projects elevated out of the local planning process was meant to deal with what FERC said were infirmities in those processes. But the rule change is not based on any finding that the current regional planning processes are unjust and unreasonable.

“Nevertheless, in its declaration that [Federal Power Act] Section 206 allows it to act, Order No. 1920 seems to take the position” that it can modify any tariff provision regardless of whether it was found to be is just and reasonable, ETCC said. “There is no statutory or judicial support for such a broad reading of the requirement under the first prong of Section 206 of the Federal Power Act.”

Environmentalists Want Stronger Requirements

A joint filing from “public interest organizations” — including the Environmental Defense Fund, the Environmental Law & Policy Center, the Natural Resources Defense Council, the Sierra Club and the Sustainable FERC project — said they support the general direction of the order and FERC’s goal to efficiently expand the grid.

Order 1920’s changes “represent the lynchpin of the commission’s multi-proceeding reform effort,” and they “applaud the commission’s extensive stakeholder engagement and thoughtful consideration of the nearly 17,000 pages of comments from nearly 200 diverse parties,” the environmentalists said.

But the commission should issue firmer mandates to get around the “inherent economic incentives of transmission providers (and their generation owners)” that lead them to avoid building out transmission to preserve local market power, they argued. FERC should specifically require that transmission planners must plan around access to cheaper generation and cannot discount that benefit.

Clean Energy Trade Groups Request Tweaks

Advanced Energy United, the American Clean Power Association, American Council on Renewable Energy and Solar Energy Industries Association — filing as the “Clean Energy Associations” — supported most of the order, but they filed a request seeking a handful of changes.

The commission was wrong to include interconnection-related upgrades in the short-term process and the new 20-year LTRTP process envisioned in Order 1920, they said. The commission also should change the order by eliminating a requirement that those network upgrades meet minimum voltage thresholds, as its rationale was ambiguous on how transmission providers must determine network upgrades for inclusion in the regional plans, they argued.

The rationale for leaving network upgrades in the short-term plans that still will be run under the Order 1000 process is that they need to be built soon under generators’ interconnection timelines.

“However, the Clean Energy Associations respectfully submit that near-term progress and long-term progress in this area are not mutually exclusive and should be pursued in parallel,” they argued.

Harvard Electricity Law Initiative Backs State Cost Allocation Rights

FERC decided against requiring transmission providers to file state agreements on cost allocation because of the precedent set when Atlantic City Electric sued it over related issues.

But Harvard Law School’s Electricity Law Initiative argued that case applies only to utility filing rights under FPA Section 205. FERC still could make it a requirement under Section 206; not doing that effectively expands Atlantic City’s legal impact.

“Atlantic City does not prevent the commission from amending the pro forma OATT to include a process for filing all regional cost allocation methods approved by relevant state entities, regardless of the transmission provider’s approval,” the Harvard group said. “Imposing a process for filing relevant state entities’ cost allocation methods would not ‘deny [utilities] their right to unilaterally file rate and term changes.’”

The new process would supplement the existing cost allocation processes, whether held by TOs or RTOs. Giving states a guarantee that their work will be given at least a review by the commission would be a marked improvement over what the rule contemplates: states gathering to come up with ideas that the RTO or utilities can reject to use their own cost allocation method instead.

“State regulators might prefer to forgo this process entirely in order to avoid bargaining in the shadow of transmission providers’ veto authority,” the Harvard initiative said. “By placing transmission providers above state officials, the final rule grants utilities leverage over their regulators, potentially interfering with regulators’ duties under state law.”