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November 14, 2024

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PJM Promises to Work with Ohio Legislators on Cost Allocation

PJM CEO Manu Asthana thanked a group of Ohio legislators in a letter Friday for their “constructive engagement” on the cost allocation implications of Illinois’ climate policies that will require fossil plants to start shutting down starting in 2030. (See Ohio Legislators Raise Concerns About Cost Impact of Illinois’ CEJA.)

Ohio House Public Utilities Committee Chair Dick Stein (R) and Senate Energy and Public Utilities Committee Chair Bill Reineke, along with 10 other colleagues, sent PJM a letter raising concerns about a preliminary estimate the RTO produced saying Illinois’ policy of retiring thermal power plants would lead to about $2 billion in transmission upgrades. In the letter and in meetings with RTO staff, they asked for a more formal estimate, including the assumption that Ohio is left out of that cost allocation.

“We appreciated the frank and open discussion regarding your concerns and your understanding of the limitations PJM faces in conducting exclusionary transmission studies,” Asthana wrote back. “The model that PJM uses for transmission analysis is not configured in a way that would let us exclude Ohio from the study results. The high-voltage transmission system is an interstate system, and electrons travel without consideration for state boundaries.”

Asthana said PJM is working to reform its markets and transmission planning, and in that effort, it hopes to better understand the impacts of federal and state policies on its system. “PJM pledges to work with Ohio policymakers to keep you fully informed of the transmission project development and cost allocation implications of our ongoing planning efforts related to this dynamic system.”

The Ohio legislators had written that the state has had success with PJM’s competitive markets, and Stein repeated that assertion in an interview with RTO Insider last week. But he said his constituents and others should not have to pay for the effects of another state’s policies.

“Ohio residents — and Pennsylvania and other surrounding states that are going to have to feed that power to them — shouldn’t be responsible for a policy another state makes that is that costly across the region,” Stein said.

Stein said he and his colleagues would continue to work with stakeholders in other states to ensure that reliability and affordability are maintained as the grid becomes more clean.

Illinois is not the only state shifting away from fossil fuel power plants to cleaner generation, the latter of which is exclusively being paid for by those state’s ratepayers. That new, renewable generation is going to add cheap power to the grid, which would tend to lower wholesale prices everywhere in PJM.

Those wholesale price impacts are part of the calculus going forward, but Stein said another concern is the capacity market and its continued ability to keep dispatchable generation that Ohio plans to keep using online. One option Stein said is off the table is state subsidies for those dispatchable plants, as the Ohio legislature does not want a repeat of House Bill 6, which was influenced by a bribery scheme by FirstEnergy. (See Former Ohio House Speaker Householder Sentenced to 20 Years in Prison.)

“All we’re trying to do is make sure we advocate for what we think is good policies here for Ohio; obviously, the people in Illinois are advocating [for] what they think the people in Illinois want,” Stein said. “And it really puts the most pressure on PJM because somehow they’ve got to bring all these elements together and make everybody happy. And as we well know, sometimes that’s not easy, if at all possible.”

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Ramping Shortfall Sparks CAISO’s 1st Summer Emergency

CAISO issued its first energy emergency alert (EEA) of the summer Thursday evening after coming up short on the ramping capacity needed to meet its peak net load as solar output rolled off its system during sunset.

The California grid operator declared an EEA-1 at 7:30 p.m. PT on a day marked by largely normal summer temperatures in most of the state’s population centers, as well as an elevated but relatively moderate system peak load of 42,266 MW, which occurred at 6:30 p.m. An EEA-1 represents the lowest level of grid emergency, called by the ISO when it confronts capacity shortages after all available resources either are in use or have been committed to use, prompting the need for conservation.

CAISO data shows that the ISO’s net load — total system load minus output from wind and solar — began to exceed the ISO’s day-ahead forecasts at about 6:40 p.m. By 7:50 p.m., as system load tapered to 40,989 MW, net load simultaneously rose to its daily peak of 37,038 MW, exceeding the day-ahead net load forecast of 35,533 MW for that five-minute interval.

“The market went into the hour a bit thin on the interchange while net demand was increasing,” CAISO spokesperson Anne Gonzales told RTO Insider. “The amount of energy available within the hour was not as robust during net load peak as solar ramped off the system, compared to other similar days. As a result, within the hour, the market was not moving enough resources to balance supply and demand while solar was ramping down.”

CAISO called on demand response resources beginning at the 7:50 p.m. interval, quickly reducing net load to levels closer to forecast. The EEA-1 was concluded at 8:30 p.m.

“As soon as the operators became aware of the situation, they manually dispatched additional generation, deployed some demand response programs available to them and made adjustments in the market to increase energy output and the EEA-1 was soon canceled,” Gonzales said.

The role of imports in the emergency remains an open question. While much of California saw moderate weather that day, neighboring areas in the Southwest continued to endure a record-setting heat wave accompanied by high electricity demand.

Asked whether “thin” conditions on the interchange indicated that imports into the ISO were lower than expected during the event, Gonzales said, “We’re still doing analysis on that. Demand came in slightly higher than forecast and more energy was needed for about an hour during the net peak load. We will know more after market analysis, however.”

Gonzales said the emergency would cause CAISO to make “adjustments going into the net peak hours to account for this going forward,” but added that it did not expect to issue a flex alert, EEA watch or call for restricted maintenance operations over the weekend.

Real-time prices during the event surged to around $250/MWh at nodes across the ISO, after hovering around $30/MWh and lower in the preceding intervals.

The EEA-1 occurred about a week after CAISO announced that this year it hit a 5,000-MW milestone for installed battery capacity, reaching 5,600 MW on July 1. California has moved aggressively to install additional batteries to help meet evening ramps, and the ISO expects to bring on an additional 2,000 MW in the next couple of months, CEO Elliot Mainzer said Wednesday during the joint meeting of the CAISO Board of Governors and Western Energy Imbalance Market’s Governing Body.

During that joint meeting, Mainzer also lauded the performance of CAISO and the wider West for managing challenging conditions in the face of widespread and persistent heat.

“Fortunately, notwithstanding a few local challenges, I think the overall grid has held up well, which I think points to certainly a lot of work within California and across the West on resource adequacy, bringing new resources onboard. Obviously outstanding hydro conditions inside California, and a tremendous amount of operational coordination and communication coordination around the region” also helped, Mainzer said.

“Of course, we have a lot of summer left. Ever vigilant, ever watchful,” he added.

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WEIM Withdraws Change to Base Schedule Deadline

CAISO’s Western Energy Imbalance Market (WEIM) last week took the unusual step of rescinding a rule change and associated functionality that it never actually implemented.

At their monthly joint meeting Thursday, the WEIM Governing Body and the CAISO Board of Governors approved an ISO staff request to withdraw a 2020 tariff revision that would have shifted the WEIM’s market deadline for submitting base schedules from 40 minutes before a delivery hour (T-40) to 30 minutes (T-30) before. The shorter timeline was intended to accommodate energy products in Bonneville Power Administration (BPA) power purchase agreements that can be scheduled after the T-40 deadline. BPA joined the WEIM in 2022. (See CAISO Floats EIM Base Schedule Rule Changes.)

CAISO’s implementation of the request always was contingent on the ISO’s ability to accommodate the change without compromising its performance in solving the real-time market, Danny Johnson, ISO market design sector manager, explained to the two governing boards.

But Johnson said testing showed CAISO “is unable to support this functionality when considered in conjunction with other real-time market enhancements,” specifically the flexible ramping product refinements that went live in the market in February.

“That initiative … increases both the reliability and the efficiency of the real-time markets through procuring flexible deliverable capacity to meet net load uncertainty, and implementing that functionality required additional computational time,” he said. “Once that was implemented, we determined we would not be also able to implement a base schedule submission deadline at T-30.”

By that time, the ISO also had determined that BPA could fully participate in the WEIM without instituting the scheduling changes.

“We largely attribute their ability to participate successfully to the tagging and scheduling practices of BPA’s WEIM neighbors,” Johnson said.

Johnson said BPA was disappointed when CAISO signaled its intent to withdraw the rule change, but also understood the technical constraints around implementing it.

In comments to CAISO, NV Energy said it had hoped to use the additional time created by the T-30 deadline to manage the variability of the net load uncertainty now included in the WEIM resource sufficiency evaluation done ahead of every delivery hour. But the utility also did not object to withdrawal of the rule change.

“Management recognizes this concern, and we’re committing to [working] with both NVE and all stakeholders to better understand the concerns on the newly implemented net load uncertainty requirements,” Johnson said.

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Biden Admin. to Auction First OSW Leases in the Gulf of Mexico

The Biden administration announced Thursday that it will auction approximately 3.7 GW worth of offshore wind energy leases in the Gulf of Mexico on Aug. 29, its first in the Gulf.

The Interior Department’s Bureau of Ocean Energy Management is responsible for selling the OSW leases, which comprise over 300,000 acres of federally owned waters, including a plot offshore Lake Charles, La., and two offshore Galveston, Texas.

The Interior Department announced in February it would make the leases available for sale. (See Interior Proposes 1st Lease for Offshore Wind in Gulf of Mexico.) A list of eligible bidders and stipulations is in the Final Sale Notice.

“The Gulf of Mexico is poised to play a key role in our nation’s transition to a clean energy future,” said BOEM Director Elizabeth Klein, adding that, “today’s announcement follows years of engagement with government agencies, states, ocean users and stakeholders in the Gulf of Mexico region.”

Map of final OSW lease areas | BOEM

Reactions

President Joe Biden on Thursday touted the administration’s OSW efforts at a shipyard in Philadelphia, while his administration released a fact sheet touting its progress on the economy and clean energy.

“We’re going to the Gulf,” President Biden said at the “steel-cutting” ceremony for the Acadia, the first U.S.-built subsea rock installation vessel for wind turbine foundations. The $246-million vessel is being built for Great Lakes Dredge & Dock Corp.

The opening of OSW auctions in the Gulf is a key moment for Biden and his “Bidenomics” agenda, which emphasizes both climate action and domestic manufacturing, since the administration wants to deploy 30 GW of OSW by 2030.

Liz Burdock, CEO of the Business Network for Offshore Wind, celebrated the event alongside Biden. “The Biden-Harris administration is helping make offshore wind a reality by bringing certainty to the permitting process, making investments in ports and transmission and incentivizing domestic manufacturing,” she said.

“It was great to be with so many offshore wind leaders today as President Biden recognized the significant milestone this vessel construction represents for the U.S. supply chain, which comes amid a flurry of actions from BOEM in recent weeks to advance projects through the permitting process,” she added.

“As President Biden made clear today during his trip to visit the Acadia vessel in the Philadelphia shipyard, America’s historic investment in clean power is bringing manufacturing home,” said Josh Kaplowitz, vice president for OSW at the American Clean Power Association.

Helen Rose Patterson, senior campaign manager for OSW at the National Wildlife Federation, also commended the lease, but added, “we look forward to working with the Interior Department, wildlife experts and companies to ensure that potential offshore wind projects avoid, minimize and mitigate impacts to migratory birds, marine mammals, sea floor habitat, and deliver benefits to coastal communities.”

The National Ocean Industries Association (NOIA), which represents both OSW and fossil fuel companies, said, “with the introduction of offshore wind in the Gulf Coast, numerous local companies will now have the opportunity to actively participate in the construction of new wind projects closer to home.”

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Dems Introduce Bill on Transmission Planning, RTO Transparency

Congressional Democrats have reintroduced legislation that would require FERC to establish interregional and interconnection-wide transmission planning processes and increase RTO transparency requirements.

Sen. Edward Markey (D-Mass.) introduced the bill to the Senate, saying the Connecting Hard-to-reach Areas with Renewably Generated Energy (CHARGE) Act would aid the development of transmission needed to bring clean energy onto the grid. Reps. Alexandria Ocasio-Cortez (D-N.Y.) and Greg Casar (D-Texas) introduced the bill in the House.

“While there has been rapid growth of renewable energy resources and skyrocketing public demand for clean energy, there is not nearly enough capacity in our power lines to bridge the gap between clean power and the cities and towns that need it. The CHARGE Act changes that,” Markey said in a statement announcing the legislation.

Interregional Transmission Planning

The legislation would require FERC to engage in interregional and interconnection-wide transmission planning at least every four years and consider the benefits of a potential project, including reduced energy and ancillary service costs, access to generation in neighboring regions, delivery of renewable energy, and improvements to grid flexibility and reliability. FERC also would be required to consider the potential of grid-enhancing technologies (GETs), such as dynamic line rating and storage-as-transmission.

Developers of interregional projects could submit costs to FERC for recovery, with cost allocation based on the project’s benefits. The bill would seek to avoid cost allocation mechanisms that might discourage energy efficiency, demand response, storage and distributed resources.

The bill also would change the cost allocation for new interconnections to prohibit utilities from requiring generation developers to bear the full — or a disproportionate — cost for network upgrades needed to connect their projects to the grid. Instead, FERC would encourage the creation of cost-sharing models that allocate costs based on the “broad set of benefits and beneficiaries for any network upgrades.”

The legislation would require RTOs to establish independent transmission monitors to oversee planning and operations and look for inefficiencies and practices that may contribute to unreasonable rates for consumers. The monitors also would review project costs, identify where non-wire or interregional project alternatives may be most cost-effective and provide guidance to transmission owners on operations, planning and cost allocation.

FERC would be required to create an Office of Transmission to review projects submitted by utilities in accordance with regional and interregional transmission planning processes. The office also would investigate ways to alleviate interconnection queue backlogs and explore opportunities to improve transmission planning and use GETs.

Ocasio-Cortez and Casar highlighted the importance of new transmission for developing renewable energy and addressing climate change.

“Our patchwork transmission system is blocking billions of dollars in new renewable deployment,” Ocasio-Cortez said. “This same transmission system is also increasingly vulnerable to widespread power outages in nearly every part of the country. The CHARGE Act is the key to updating this transmission network so we can plan for and meet the growing demand for grid resilience and renewable energy across the U.S.”

“As the climate crisis worsens, we must do everything we can to increase grid reliability across the country. That’s why we must pass the CHARGE Act,” Casar said. “Every single family should be able to rely on their utilities.”

Increased RTO Transparency Requirements

The bill would introduce several transparency requirements for RTOs and the commission, including stakeholder meetings being recorded and transcribed, records of votes being public and RTOs being subject to the Freedom of Information Act.

A 30-member advisory committee would be established by FERC to provide recommendations on the governance and oversight of RTOs and their stakeholder processes, with the goals of promoting competition, reliability and affordability in transmission planning. The committee also would consider improvements that could be made to transparency and decision-making in non-RTO regions.

Consumer organizations would be granted full voting and participation rights in stakeholder meetings, and RTOs would be required to provide intervenor compensation for public interest participation in RTO processes.

A handful of the transparency provisions mirror state initiatives relating to RTO governance. A bill introduced in the Maryland House of Delegates this year would have required utilities participating in stakeholder meetings to report their votes to the state each year. (See Maryland Bill Would Require Utilities to Report Votes at PJM.)

Additionally, the West Virginia Public Service Commission in March filed a complaint with FERC seeking access to PJM’s Member Liaison Committee, which is open only to voting members. (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

Under the Markey bill, FERC and utilities would be required to coordinate with EPA and the Energy Information Administration to create a public database with hourly operating data for generators including fuel type, marginal greenhouse gas emissions per megawatt-hour and other attributes updated as close to real time as possible.

The legislation would direct the National Academies of Sciences, Engineering and Medicine to work with EPA, DOE and FERC to draft a public report identifying the effects on consumers of procuring energy competitively outside of utilities in markets administered by RTOs or other independent organizations compared with noncompetitive models. The study would account for factors such as cost savings, improved grid reliability and GHG emissions.

Public Interest and Climate Organizations Endorse Bill

Several climate and consumer advocacy groups endorsed the bill, including the American Council on Renewable Energy (ACORE), Americans for a Clean Energy Grid (ACEG), the Natural Resources Defense Council and Public Citizen.

“Our clean energy transition depends on building new high-capacity transmission lines. We need legislation that will accelerate this development, unlocking new domestic energy resources and making sure the lights stay on during severe weather episodes like the intense heat waves we’ve experienced across America this summer,” said ACEG Executive Director Christina Hayes.

Tyson Slocum, director of Public Citizen’s Energy Program, said the bill’s transparency and transmission monitor requirements would ensure that transmission development proceeds with consumer protections built in.

“Among many other accomplishments, the legislation would impose needed transparency standards, public accountability and governance reform for America’s private RTO grid operators, including subjecting them to the federal Freedom of Information Act; empower the public and energy justice communities with access to resources to participate in FERC and RTO proceedings by requiring FERC’s Office of Public Participation to provide intervenor funding, and; ensure the electric transmission buildout maximizes consumer protections through a new independent transmission monitor,” he said in a statement.

ACORE President Gregory Wetstone said the bill would establish critical provisions around interregional planning and would promote reliability by establishing minimum transfer requirements between transmission planning regions during severe weather.

“This legislation lays the groundwork for the construction of critical interstate transmission lines. The bill also reforms participant funding, a crucial step to help bring more clean energy resources onto the grid, and establishes a sorely needed mandate for a minimum transfer capacity between grid planning regions that will bolster reliability and better enable our electric power system to withstand increasingly frequent extreme weather events,” he said.

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CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines

CAISO’s Board of Governors on Thursday approved a proposal that will allow transmission projects outside California to join the ISO under a new subscriber-funded model that avoids allocating costs to ISO load-serving entities.

Board members praised the “subscriber participating transmission operator” (PTO) proposal, which is intended to help California tap clean energy resources in other parts of the West to meet its ambitious greenhouse gas reduction goals while reducing financial risks associated with new transmission. Modeling from the California Public Utilities Commission (CPUC) shows the state will need to acquire more than 4,800 MW of new out-of-state wind resources to hit its midcentury targets.

“I’ve been here five years. Other than adopting the day-ahead market, I’m trying to think of something as big, and I can’t, so thank you for this elegant solution,” board Chair Mary Leslie told the CAISO executives who presented the plan during Thursday’s monthly board meeting.

“This continues ISO leadership,” Governor Angelina Galiteva said. “We were leaders with policy-driven transmission, and now this as well, so I hope we’re successful. I’m actually confident that we will be.”

Under the proposal, the developer of a transmission project not selected in CAISO’s transmission planning process will have the ability to solicit generator customers to subscribe to service on a line designed to deliver energy into California. The project could then turn operational authority for the line over to the ISO, joining the balancing authority area as a “subscriber PTO” not eligible to recover their costs under the ISO’s transmission access charge (TAC).

The proposal calls for subscribers to have priority use of the line and be exempt from CAISO transmission and congestion costs, including the TAC. Non-subscribers would be required to pay to use the line at a FERC-approved rate that does not exceed the TAC.

The plan also would require subscribing generators to pay the ISO’s existing PTOs to cover upfront costs for any system upgrades needed to facilitate the new lines’ interconnection into California, but they would be reimbursed for those costs over the following five years. Any future network upgrades associated with future generation interconnection or transmission planning requirements would “be recovered by the subscriber PTO through a cost-of-service rate approved by FERC,” the ISO said.

According to Deb Le Vine, CAISO’s director of infrastructure contracts and management, the ISO will study integration of proposed subscriber lines through its transmission interconnection process. She told the board that the grid operator will “set a higher bar” for including subscriber PTO lines in its 20-year transmission base case than it does for lines chosen through the planning process.

“We don’t want to put it into our base case prematurely, assuming that the line is there, and start making solutions based on the line being there,” Le Vine said.

To be included in the base case, she said, a subscriber PTO must execute a transmission applicant agreement with the ISO; have its subscribing generators complete interconnection agreements; and provide the grid operator with a notice to proceed.

Subscribing generators that go through the transmission planning process would be exempt from the ISO’s separate — and currently lengthy — generator interconnection process.

“Obviously, this is a brand-new service,” Le Vine said. “We’re trying to meet the needs of California, [and] we’re trying to come up with solutions that allow load-serving entities to better determine the best-fit portfolios. And we’re trying to use the existing functionality that the ISO already has in its toolkit, and therefore have minimal changes needed to our systems.”

Le Vine said that in allowing for interconnections to other parts of the West, the model will help improve the performance of the proposed extended day-ahead market in CAISO’s Western Energy Imbalance Market, support resource adequacy and “enhance resilience on the grid.”

‘The Best Wind’

The subscriber PTO model already has one participant waiting in the wings: the proposed TransWest Express transmission project, a 700-mile line designed to carry 3,000 MW of wind energy from Wyoming to Nevada, where it will connect to the CAISO grid.

In March, FERC approved an agreement that would allow TransWest to continue its efforts to become a CAISO PTO under the model, pending the commission’s approval of the ISO’s proposal. Among other things, the agreement allowed TransWest’s subscriber, the Power Company of Wyoming — owner of a 3,000-MW wind farm being constructed in south-central Wyoming — to be studied under the ISO’s generator interconnection queue cluster 15, starting April 1. (See FERC OKs CAISO-TransWest Move Toward PTO Status.)

Speaking during the board meeting Thursday, David Fuller, TransWest director of business development, said, “Not only will the [subscriber] PTO model access new resources, it will access the best wind resources in the continental United States — from Wyoming. … This model allows the LSEs and the ratepayers in California to leverage private investment to bring this resource to California, and probably do it sooner and cheaper than other ways and all without increasing the TAC.”

Neil Millar, CAISO vice president of transmission planning and infrastructure development, also pointed to how the model reduces risk for California by making developers such as TransWest responsible for attracting subscribers and ensuring the financial viability of their projects.

“Without that, the project wouldn’t move forward, and the ISO is basically kept whole because we’re not supporting the cost of the TransWest Express project itself,” Millar said.

CAISO CEO Elliot Mainzer emphasized how the model will assist in the “huge lift” facing California, which will need to bring on about 7,000 MW of new clean resources every year for the next two decades to meet its midcentury GHG targets. He said the procurement orders stemming from the state’s integrated resource plan show the need to acquire “a significant fraction” of the state’s needed resources and transmission from out of state “in terms of reaching total supply and for the diversification benefits in terms of reliability and affordability.”

“The subscriber participating transmission owner model is our effort to work with developers out of state to create additional optionality for the utilities inside California,” Mainzer said.

CAISO expects to file the subscriber PTO proposal with FERC in September and anticipates a decision in November.

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IRA Gets US Emissions Close to Pledged Levels, Report Finds

The U.S.’ current policies have it on course to cut emissions by 32 to 51% below 2005 levels by 2035, which is an improvement over previous years but still short of its pledges under the international Paris Agreement, the Rhodium Group said in a report released Thursday.

The country is on track to get to 29 to 42% cuts by 2030, while the Paris Agreement calls for cuts of 50 to 52% by that year.

Rhodium Group releases a version of its “Taking Stock” report every year, and this year it has the benefit of a better understanding of how the Inflation Reduction Act is going to be implemented. The law has Rhodium predicting the power sector will see the largest declines in greenhouse gas emissions in its history of tracking emissions.

“The power sector in particular looks quite different in 2035 compared to today, with zero- and low-emitting power plants making up 63 to 87% of all generation that year, up from around 40% in 2022,” the report said. “Electric vehicles also continue their rapid growth, and, taken together, this progress on decarbonization also reduces household energy bills by an average of $2,200 to $2,400 per year in 2035 from 2022 levels.”

Getting there will be challenging, with the country needing to add 32 to 92 GW per year of wind and solar, while its actual annual record is roughly at the very bottom of that range. That level of deployment “faces headwinds in nearly every direction,” with more work to be done on the supply chain, interconnection, transmission, siting and an expanded workforce.

“Without the IRA, cost competitiveness would be one of the primary barriers to clean energy deployment,” Rhodium said.

While new wind and solar had proven to be cost-competitive with new natural gas before the law, they also have to compete with existing fossil fuel generators, which are either partially or entirely depreciated.

“But if cost is less of a barrier, all the other headwinds remain,” Rhodium said. “Until now, relatively less attention has been paid to these other challenges because cost was front and center. That means policy solutions for overcoming these barriers are less developed and have less political momentum.”

Rhodium estimates “economically rational” deployment of renewables, which means some of those other headwinds are not fully taken into account in the report. The group said it planned to tackle them more completely in future research.

Taking into account announced retirements and future economic decision-making by generators, Rhodium expects the trend of coal plant retirements to accelerate in the coming years, averaging 22 to 23 GW from 2023 to 2025, compared to 12 GW over the past five years. The trend slows down in later years because of a much smaller coal fleet.

“Additions of combined cycle and peaker gas plants also accelerate into the 2030s in the mid- and high-emissions cases,” the paper said. “But gas capacity growth is effectively flat through 2030 in the low emissions case and then starts to decline in the early 2030s.”

The paper’s power sector emissions projections include the impact of federal incentives from the IRA such as the extended clean energy tax credits; tax credits for nuclear, carbon capture and storage; current EPA rules such as the Mercury and Air Toxics Standards; and state policies such as renewable portfolio standards and offshore wind mandates.

EPA’s proposed power plant rule to limit greenhouse gases would require a mix of carbon capture retrofits, hydrogen blending, natural gas co-firing, federally enforceable retirement decisions and capacity factor limitations. The agency has yet to take comments on its proposal, which is likely to change before it is finalized. (See EPA Proposes New Emissions Standards for Power Plants.)

“We generally adopt EPA’s proposed phase-in schedule and the stringency of emissions reductions, but we offer a high degree of flexibility for states to create and submit plans for achieving equivalent levels of emissions reductions,” Rhodium said.

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Stakeholders Puzzled by MISO Transmission Service Requirements for Battery Storage

CARMEL, Ind. — MISO stakeholders are trying to figure out what transmission service requirements the grid operator has in place for battery storage that charges from the grid.

Stakeholders have asked MISO to clear up its transmission service requirement process for incoming battery storage that intends to charge from the grid. They said there are inconsistencies and ambiguous language between MISO’s business practice manuals and tariff as to whether battery storage needs to secure yearly, firm point-to-point transmission service for storage, or non-firm service. MISO maintains that storage that charges from the grid is required to obtain long-term, firm, point-to-point service, not the interruptible network service option.

At a July 19 Planning Advisory Committee meeting, WEC Energy Group’s Chris Plante outlined stakeholder concerns that MISO’s interpretation that storage should acquire point-to-point service is overly restrictive compared to FERC requirements and “severely limits the value” of energy storage resources.

FERC’s Order 841 requires that “applicable transmission charges” should apply when a storage resource is charging from the grid to resell energy later.

Several storage developers agreed that MISO’s reading of Order 841 will hurt their bottom lines. Some argued that storage charging behavior is similar to load, and that storage resources already naturally avoid charging during periods of peak demand. Multiple stakeholders said MISO needs storage to help combat deepening capacity shortage risks down the road. (See OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028.)

Plante raised the issue during multiple spring planning meetings. He said he thought MISO’s business practice manuals are light on authority when standalone battery storage connects to the transmission system and intends to charge from the grid.

Plante said MISO’s rules are vague on whether MISO’s non-firm Network Integration Transmission Service could fulfill the requirements of Order 841. He also said it’s unclear as to whether MISO’s interconnection process for storage resources considers its transmission service requirements. Finally, he said MISO is ambiguous as to whether transmission service requirements apply to storage connected to the distribution system.

MISO’s Planning Advisory Committee members agreed to take up the issue for discussion at future meetings.

“If we’re going to be relying on batteries as a large source of our generating fleet in the future, then it will have to charge in areas that are different from what we have today,” MISO’s Andy Witmeier said.

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MISO Aims for Manageable Interconnection Queue

CARMEL, Ind. — MISO is proposing an approximate 73-GW annual limit on project proposals, tripled entry fees, more ironclad land requirements and escalating penalty charges in its quest to oust speculative projects and lighten its gridlocked interconnection queue.

MISO shopped six new rules Wednesday to limit the interconnection requests it will accept and under what circumstances developers can withdraw project proposals. (See MISO Committed to Crackdown on Interconnection Queue Submittals, Departures.) The package of rules includes introducing an escalating, automatic penalty upon withdrawal of project proposals, imposing a 60%-of-peak-annual-load megawatt limit on the total number of new requests per year and enacting a 10% cap of that total size limit on the projects individual developers can submit annually.

“We do not want to slow the energy transition down, but the more projects you have in your queue, the longer it takes to study them,” Director of Resource Utilization Andy Witmeier said at a July 19 Planning Advisory Committee (PAC) meeting.

MISO’s Andy Witmeier | © RTO Insider LLC

Witmeier said MISO considers a queue that adds 73 GW of annual projects more achievable in terms of reliability studies. Last year, MISO received about 171 GW of interconnection applications. As of last month, MISO’s interconnection queue contained 1,412 active generation projects totaling almost 241 GW. Historically, more than 70% of interconnection requests never complete MISO’s queue.

MISO is waiting to file for and receive FERC approval on the proposal before it closes its currently open-ended 2023 queue application window. It hopes to wrap up accepting applications by the end of the year, later than its usual September deadline. Witmeier said if MISO kicks off studies before it has the new restrictions in place, it could be hit with as much as 200 GW in new generator interconnection requests.

“MISO only has an approximate 121-GW peak load. Where are we going to put those additional megawatts? We’ll have to shove them off on our neighbors. We have to set some type of limit so we can get a proper-sized queue and have realistic studies,” he said.

But Witmeier said he had “concerns that FERC isn’t going to go for” MISO’s proposed cap on individual developers because of the potential for discriminatory treatment. MISO proposed an annual cap of 60% of its average 121-GW peak load (73 GW) and that individual developers be limited to 10% of the total, or 7,300 MW. Witmeier said MISO likely will have to create an attestation form for developers where they verify parent companies or subsidiary status to enforce such a cap.

Invenergy’s Sophia Dossin said her company is “deeply concerned” over the proposed megawatt limits, saying it would set the stage for a lottery where the most prepared developers’ projects could be barred from consideration. Others agreed that MISO’s megawatt limits could affect the market forces of renewable energy development.

Witmeier said MISO likely will hike its $4,000/MW first milestone fee to $12,000/MW. The second milestone fee is set to be $1,000/MW or 20% of the cost of identified network upgrades, whichever is greater. The third milestone fee would be at least $1,000/MW or 30% of network upgrades.

“We think the [Inflation Reduction Act] has changed the dynamics of our interconnection queue,” Witmeier said, adding that MISO hasn’t increased the milestone fees it charges developers since 2017.

MISO is proposing to use its larger, second milestone fee as the basis for a new, automatic penalty schedule for interconnection customers who withdraw projects. MISO is proposing to keep 10% of the first milestone payment if projects are removed before the start of the queue’s definitive planning phase, 25% of the payment if projects drop out at the queue’s first decision point, 50% at the second decision point, 75% during the queue’s final phase and 100% at generator interconnection agreements (GIAs) and beyond.

Witmeier said the penalty schedule relies on an expanded definition of withdrawn projects’ harm on lower-queued projects. He said MISO will use the pool of money it collects to spread among other generation projects, some of which were banking on sharing network upgrade costs with the dropouts. He said the move should cut down on the instances of cascading project withdrawals in the queue.

Witmeier also said MISO will require interconnection customers to secure 50% site control from generator site to point of interconnection upon application and 100% site control to the point of interconnection before developers can negotiate GIAs.

“If you don’t have site control at the time of GIA, you are not a viable project,” he said.

Witmeier said the megawatt limit on individual developers might only serve as a “backstop” against an unmanageably large queue because MISO is creating a more exclusive club of projects that line up in the first place through higher fees and stricter land requirements.

MISO retained Charles River Associates to conduct an independent review of the RTO’s recommendations, Witmeier said. He said while the review is still ongoing, the firm has initially deemed the set of rules to be reasonable.

However, Witmeier said if stakeholders are adamantly opposed to one of the new rules, MISO will consider lowering dollar amounts or adjusting requirements.

“We don’t know how each of these levers will impact the queue. There’s no way to know. Interconnection customers aren’t Goldilocks,” Witmeier said in response to stakeholders’ questions on how the queue might look emerging from the changes.

Staff will again discuss the stricter queue entry and exit rules at the Aug. 30 PAC meeting. Also, MISO has said it will consider stakeholders’ ask for a special meeting on the suite of changes. Many said the 45-minute time slot MISO allotted on its July 19 PAC agenda for discussion of the proposal was insufficient. PAC leadership was forced to stop accepting stakeholders’ questions to MISO staff after the discussion exceeded two hours.

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MISO Trims Minnesota Line Route in JTIQ Portfolio

CARMEL, Ind. — MISO announced this week that it has shortened one of the 345-kV lines contained in its $2 billion Joint Targeted Interconnection Queue (JTIQ) portfolio with SPP, which will lower costs.

At a July 19 Planning Advisory Committee meeting, Director of Resource Utilization Andy Witmeier announced that MISO will replace the Brookings County-Lakefield 345-kV project in Minnesota with the shorter Lyons County-Lakefield 345-kV project. He said MISO was making the change because it approved Northern States Power’s proposal to install a second 345-kV circuit between the Brookings County and Lyon County substations in Minnesota for reliability reasons as part of the 2022 MISO Transmission Expansion Plan. That nearby project negates the need for a full-length line.

Witmeier said the “much shorter line, as the crow flies,” represents a significant savings for customers. He said the new line will solve all the same constraints as the original design but with a better benefit-to-cost ratio. MISO has already performed economic and reliability analyses on the shorter route. Transmission owners Xcel Energy and ITC Holdings will still build the line.

Witmeier said the JTIQ portfolio, which was finalized in 2021, is subject to revisions as MISO and SPP perform their annual transmission planning. He also said since the revised line remains wholly in Minnesota, it won’t require a change in permitting jurisdiction.

MISO has yet to reveal how much ratepayers can expect to save on the shorter line. Last month, the RTOs announced that the portfolio’s cost estimate had nearly doubled to $1.9 billion from a little more than $1 billion in 2021 due to the rising cost of materials and labor and more accurate line route estimates. (See JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B.)

Witmeier said he didn’t think the more economical line would affect the states’ application for the JTIQ portfolio to receive up to a 50% funding match from the Department of Energy’s Grid Resilience and Innovation Partnerships program.