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September 23, 2024

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SPP Pushes Back on Western Market Delays

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. 

SPP filed the proposed Markets+ tariff with FERC in March. However, the commission issued a deficiency letter in July asking the RTO to respond to 16 issues it found lacking in the design (ER24-1658). (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.) 

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 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 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.” 

For its part, SPP has increased its public outreach, stressing its ability to build and manage markets and transact energy over seams. It has also created a spiffy website dedicated to Markets+. (See SPP’s Experience with Seams Could Help Markets+.) 

“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. 

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Berkeley Lab: Solar-storage Hybrids Reshaping the Grid

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.”

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MISO Board Week Covers Supply Worry, SoCal Utility Exec Addition, $400M Budget

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 timeframes.

“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.

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ISO-NE Planning Advisory Committee Briefs: Sept. 18, 2024

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. 

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FERC Approves SPP Make-whole Payments Under Order 831

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.

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FERC Dismisses Muni’s Complaint Against Dominion over RGGI Charges

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. 

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MISO: Hurricanes, Heat Wave Noteworthy Against Relatively Peaceful Summer

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.  

MISO’s board members and leadership praised operators for pulling through the overnight electrical island caused by Hurricane Beryl in early July. (See MISO: Hurricane Beryl Caused Electrical Island in Texas.)  

“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 Directors Trip Doggett and Phyllis Currie | © RTO Insider LLC 

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.)  

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MISO Members See No Easy Fix for Making Transition Affordable

INDIANAPOLIS — At their quarterly meetup, MISO members largely agreed there won’t be an easy path to achieving decarbonization affordably for customers.

“We’ve gone from talking about rates, to talking about energy burden to now talking about energy wallet,” Sarah Freeman said, introducing members’ chosen topic, “Affordability, Sustainability and Reliability,” at a Sept. 18 meeting of MISO’s Advisory Committee.

“I really don’t think we’re prepared for what the transition is going to cost in the next five to 10 to 15 years,” said Michelle Bloodworth of coal advocate America’s Power. Bloodworth said customers of rural power cooperatives will be particularly hard hit.

Arkansas Public Service Commission consultant Keith Berry said affordability is a chief issue in MISO South, which he said contains some of the poorest residents in the nation. He said he worries what MISO’s third long-range transmission plan (LRTP) portfolio — which will focus on MISO South — may do to customer bills.

“We look with some trepidation on what the costs of Tranche 3 might be,” Barry said.

The Union of Concerned Scientists’ Sam Gomberg said MISO’s Environmental Sector views the three words as interconnected.

Sam Gomberg, Union of Concerned Scientists | © RTO Insider LLC 

“If electricity is cheap, but it’s fouling your waters and making our planet uninhabitable, then it’s not affordable,” Gomberg said.

Clean Grid Alliance’s David Sapper said to further all three, MISO should “unlock the queue without resorting to a queue cap,” finding ways to bring new resources online quickly.

“Resource expansion is the cornerstone of competition, so we need to get the queue moving,” Sapper said. He also said MISO’s transmission owners should use grid-enhancing technologies and dynamic line ratings to leverage the most they can from the existing system and host the greatest number of new megawatts.

Other members said some transmission projects will be better than others at delivering value.

Yvonne Cappel-Vickery, of the Alliance for Affordable Energy, said the industry should work to put a stop to inefficient transmission “overbuilds that starve the regional transmission planning process.”

Cappel-Vickery said some utilities “flock” to new power plants and expensive local lines that come “at the expense of bringing lower-cost resources” to their territories. She said the problem is particularly pronounced among utilities that own transmission and generation.

LS Power’s Sharon Segner also said comprehensive, regional planning needs to trump the local projects that are ubiquitous in MISO’s annual transmission planning.

Gomberg said members must ask themselves if they’re willing to bear near-term costs for long-term benefits.

“If we underbuild, we’re going to leave benefits on the table and risk affordability, sustainability and reliability,” he said, adding that regional transmission needs to be “smart and targeted.”

ITC’s Brian Drumm said there’s no substitute for transmission to achieve all three objectives. He said there’s current evidence that MISO and members have been underbuilding for years.

ITC’s Brian Drumm | © RTO Insider LLC 

Iowa Utilities Board Member Josh Byrnes agreed the system to date has been underbuilt.

Multiple stakeholders said bills are opaque and confusing for customers and said some efforts from the industry to help ratepayers understand what’s in their bill could go far.

Gomberg called for a greater commitment to transparency from utilities and MISO but added the simple fact is shareholder-beholden utilities exist to make money.

Gomberg said utilities may include “line items for things that they don’t want to pay for” in customer bills, “chip away at regulatory oversight” and approach state commissions with “inflated costs” in rate cases.

“That’s just the world we live in,” he said, qualifying that he wasn’t taking a shot at capitalism.

In a separate discussion on the state of MISO’s seams, Sustainable FERC Project’s Natalie McIntire said MISO ought to do more to build cross-border transmission.

“As the energy transition occurs and more and more renewables are added to the system and weather events get more extreme, the ability to share across our seams is going to be more important,” she said.

McIntire said MISO so far has provided “very little to no” insights into the scope of their recently announced interregional transfer capability studies with PJM and SPP.

On the other hand, the Coalition of Midwest Power Producers’ Travis Stewart said MISO might need to reevaluate “the amount that we lean on our neighbors.”

Stewart said with PJM anticipating supply shortfalls, MISO soon won’t be able to rely on the few gigawatts it receives daily from its eastern neighbor.

“Those megawatts are going away,” Stewart warned, saying MISO would be well-served by internally becoming resource and energy adequate so neighbors can begin to lean on MISO.

Vice President of System Planning Aubrey Johnson said seams projects might have been inhibited thus far because other RTOs haven’t been as interested in scenario-based long-range transmission planning as MISO has been.

“Ultimately, I do think there’s an attitude of ‘solve your own problems first,’” Johnson said. He added that MISO’s neighbors’ interest in interregional projects might grow after they approve their own major portfolios.

“I think Order 1920 is going to bring the other regions along,” Drumm agreed.

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July Sees New Western Peak Despite Moderate CAISO Demand

The Western Interconnection reached a record-breaking peak load July 10 despite relatively moderate demand in CAISO, the ISO said during a Sept. 18 meeting of its Market Performance and Planning Forum.

“When you look holistically across the West, it happens to be the warmest July on record, and that really drove the high loads in the Western Interconnection,” Guillermo Bautista Alderete, director of market analysis and forecasting at CAISO, said.

The Western grid’s peak reached 167,988 MW, slightly higher than the previous record in 2022. July saw many hours with high demand, Alderete said, and so the peak wasn’t necessarily an outlier for the month.

Despite record-breaking conditions across the West, temperatures in the CAISO system where the demand was concentrated were “not that extreme,” keeping ISO loads moderate, with a peak of about 45,000 MW — well below the historical peak of 52,000 MW.

“At the end of the day, it is not only how high the demand is, but also how well-equipped we are to handle that level of demand,” Alderete said.

‘Substantial Volumes of Exports’

Favorable resource adequacy conditions in CAISO helped support high loads in the West.

“We need to have enough resource adequacy capacity to be able to meet our actual load plus our reliability obligation … When you put that obligation together and compare that against the resource adequacy capacity that we have available, you can see we were within a healthy margin,” Alderete said. “We were never even really close to hitting the resource adequacy showing level, and that means that the levels of demand that we have in the system were moderate enough that the resource adequacy capacity was sufficient to meet that obligation.”

CAISO experienced a marginal increase in RA capacity from 2023 to 2024, a trend the ISO expects will continue over time. Given the moderate levels of demand in the ISO’s balancing authority area in July, and even on the most critical days of July 23-25, RA capacity was enough to meet the load obligation.

CAISO’s prices increased as expected in July, reaching peaks on July 24. In June, average prices were typically below $50/MWh, while in July they rose to $200/MWh for hours ending 7:00 p.m. and 8:00 p.m. Prices in the Pacific Northwest remained low compared with California and the Desert Southwest.

“Practically speaking, even those prices are moderate given all the conditions that we have when we look at the real-time,” Alderete said.

Import and export levels were close to historical norms as well. Most imports with self-schedules or bids at or below $0/MWh were cleared in both the day-ahead and real-time markets, though up to 640 MW of bid-in RA couldn’t clear given path derates on the Malin intertie because of the impact of the Park Fire.

CAISO cleared “substantial volumes of exports” in July due to conditions driven by record loads across the Western Interconnection, resulting in several days of net exports.

While the ISO had to reduce exports on very few days, its hour-ahead scheduling process on July 24 reduced up to 900 MW of exports.

The Western Energy Imbalance Market (WEIM) provided operational benefits and offset risk for members by facilitating assistance energy transfers (AETs), which allow a participating BA to receive energy when it does not meet the market’s resource sufficiency requirements ahead of a trading interval. Ten WEIM balancing areas opted into the AET program in July, the largest rate of participation since the program’s inception, Alderete said.

The ISO in July also identified three issues related to the residual unit commitment (RUC) process and incorrect reporting of exports.

“I would say, in the grand scheme of things, they are relatively minor items, but we want to provide the transparency,” Alderete said.

On July 4, the RUC process triggered undersupply infeasibility — which indicates a potential supply shortage — without attempting to reduce low-priority exports to maintain supply, but the issue was fixed the following day.

The month also saw an incorrect reporting of export reductions in the customer portal that was fixed July 9, as well as an incorrect loss of high-priority status for certain exports. In particular, under different permutations of bidding in day-ahead and real-time markets, different bid validation rules triggered the unintended loss.

CAISO is assessing whether to revise the validation rules and has resolved all other issues, Alderete said.

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FERC to Consider Special Interconnection Rules for Tribal Energy Projects

WASHINGTON — FERC said it will work with federally recognized tribes on whether it needs to issue a new rulemaking to address their issues interconnecting renewable resources to the grid. 

The announcement at the commission’s Sept. 19 open meeting comes just over a month after the Alliance for Tribal Clean Energy filed a petition for an expedited rulemaking on the subject, arguing the few tribes able to build major generation projects face unique issues in hooking them up to the grid (RM24-9). 

“This will be the first time that the commission engages in tribal consultation on an electric markets issue,” FERC Chair Willie Phillips said at the meeting. “Improving the commission’s tribal engagement and consultation practices is one of my top priorities and a commitment that’s reflected in our equity action plan.” 

FERC is offering all its staff a training opportunity with Maranda Compton, an expert on tribal legal issues and a citizen of the Delaware Tribe of Indians, Phillips said. 

The alliance argued that some FERC standard rules, such as commercial-readiness deposit requirements and withdrawal penalties, do not make sense with its members’ projects. 

“Tribal projects that advance to the point of seeking interconnection are not speculative,” the tribes said. “They are not undertaken to take a big risk in hopes of making a big profit. They are not motivated to take advantage of fluctuations in the market. They are pursued to self-serve tribal needs for electricity to advance the goals of lower electricity rates, revenue for tribal governments, tribal economic development and tribal self-sufficiency.” 

Tribal lands are home to some of the best energy resources in the country, but on average, they pay some of the highest energy rates, with 56% paying more than double the national average, they said. 

“While tribal nations are eager — indeed, desperate — to change their economic predicament and energy circumstances, they find themselves stymied by unworkable and unduly burdensome rules that fail to account for tribal nations’ unique organizational structures and funding constraints,” they said. 

Building utility-scale generation projects can help redress tribal poverty and energy inequity through economic development, creating revenue and jobs, and promoting self-sufficiency, they wrote. They asked FERC to adopt limited and narrowly tailored commercial-readiness and withdrawal penalty rules that reflect their financial barriers, such as not being able to take out loans on land they hold in common among all their citizens. 

The issue also came up at the recent technical conference on interconnection, during which the Oceti Sakowin Power Authority’s general counsel, Jonathan Canis, described the difficulties in trying to get a major project connected to the grid. 

The power authority is jointly owned by seven Sioux tribes and is trying to build two wind farms in western South Dakota, which is a high-voltage transmission “desert,” Canis said. Interconnection studies would have the authority pay $250 million for the transmission on its own. 

“Of course, that made our projects economically infeasible,” Canis said. “To put it in perspective, our entire estimated budget for development and construction for two wind farms is $1.1 billion, so this increased our total project cost by 20 to 25%. We had to withdraw from the queue, and our projects are now on hold. We’re focused 100% on how to get back in there and how to make it affordable.” 

The authority worked with the Western Area Power Administration and Basin Electric Power Cooperative to develop a transmission solution, a 700-mile 345-kV project that would cross Sioux land. But only parts of it were picked by SPP for the regional transmission plan, and those do not touch tribal lands, Canis said. 

The Department of Energy’s Loan Programs Office also has the funding for tribal energy projects, but that has never been used, outside of one commitment of $74 million for a solar microgrid to serve a big casino, Canis said. 

“We’re going to ask Congress to repurpose that fund to another DOE office that will really put that money to work,” Canis said. “And to put it in perspective, there’s only about five tribal development companies in the country, and there are not that many tribes with enough land area to develop their own wind farms. So, a fraction of that $20 billion could fix all our problems.”