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November 5, 2024

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MISO Releases JTIQ Portfolio Cost-allocation Details

CARMEL, Ind.— MISO last week released details about how it will allocate costs for its portion of the $1 billion Joint Targeted Interconnection Queue (JTIQ) portfolio of 345-kV projects with SPP.

The grid operator plans to recover a 90-10 split from incoming generation and load, respectively, for their cost share of the JTIQ portfolio through a monthly charge. MISO said it and SPP’s generation developers will make fixed payments that reduce the select transmission pricing zones’ revenue requirements over 20 years.

During a Planning Advisory Committee (PAC) meeting Wednesday, MISO counsel Chris Supino said the RTOs will use a subscription model for JTIQ planning cycles. When 125% of the portfolio’s megawatts are spoken for, it will be considered fully funded.

Should the grid operators come up short on new megawatts before all JTIQ projects are in-service, load will temporarily pay for the unclaimed megawatts. Generation projects that queue up will repay load later.

MISO staff said they are still outlining the process of what happens when a JTIQ portfolio doesn’t have enough willing takers of transmission capacity through new generation in the queue. However, Supino said it’s unlikely that the portfolios won’t be fully subscribed and funded, as they’re planned to support the evolving resource mix.

Supino said MISO is considering adding a new JTIQ participation agreement to its generator interconnection agreements that would bind parties to the cost schedules’ terms.

Potential federal funding might complicate the process. The Department of Energy in early March said the RTOs and two member entities can apply for full funding under its Grid Resilience and Innovation Partnerships (GRIP) program. (See DOE Clears JTIQ Projects to Proceed with Funding App.)

Clean Grid Alliance’s Beth Soholt asked how payments might be modified should the DOE award funding to the portfolio.

“That’s a great question, but we can’t assume we’ll have a pot of money until we actually get that money,” Supino said.

Supino said staff plans to mention the DOE application when memorializing the JTIQ study and payment process in its joint operating agreement with SPP. The RTOs plan to file with FERC as early as July.

Supino said he doesn’t yet know how DOE funding will affect repayments or reimbursements.

JTIQ portfolio map with costs (MISO and SPP) Content.jpgJTIQ portfolio map with costs and adjusted production cost benefits | MISO and SPP

During a Tuesday cost-allocation working group meeting, Mississippi PSC consultant Bill Booth asked MISO to provide more details around the payments’ “timing and flow.” He said he wanted to know whether cost assignments to load will be capped and how they would be tracked in the case of temporary overpayment.

Sustainable FERC Project’s Natalie McIntire said that analyses indicate load will receive 20% on the JTIQ projects’ benefits, but only shoulder 10% of the cost.

Stakeholders asked during the PAC meeting whether staff will begin a JTIQ portfolio for the MISO-PJM seam.

Dave Johnston, an Indiana Utility Regulatory Commission staffer, said he thought it was premature to ponder a MISO-PJM JTIQ portfolio when the MISO-SPP’s process is untested and cannot be deemed a success yet.

MISO’s Andy Witmeier said in March that it’s more cost-effective for comprehensive seams planning to replace the RTO’s “back-and-forth, across the fence” affected system study process with SPP that identities expensive network upgrades.

“A lot of time those solutions are too costly for those set of projects to take on,” Witmeier said. He said it’s appropriate that most JTIQ projects’ costs be allocated to generation because they are designed to facilitate new resources.

“They’re not being built to fix market-to-market congestion or increase transfer capability, he said. “There might be tertiary benefits.”

“This is all new and novel, and if we want this to work, we’re going to have to accept some level of risk,” SPP’s David Kelley said. “I truly believe this is going to be successful and our new way of planning.”

That risk could be reduced considerably if the JTIQ portfolio wins up to a 50% share of funding through the GRIP program.

The Minnesota Department of Commerce is leading the DOE application, due May 17, with help from the Great Plains Institute. The Institute’s Matt Prorok said during April’s Organization of MISO States board meeting that the parties have a “compelling case.”

If the federal dollars are approved, the awards will be granted to RTOs and transmission developers. Prorok said parties must negotiate any awarded grant.

Prorok said the DOE application shouldn’t interfere with the RTOs’ cost-allocation discussions with their stakeholders.

“If the DOE can help us out with funding, I think those [cost-allocation] discussions will go very smoothly,” Kansas Corporation Commissioner Andrew French said during the Gulf Coast Power Association’s MISO-SPP conference in March.

“I hope JTIQ can move forward, and we can use it as proof of concept,” he said.

Aubrey Johnson, MISO’s vice president of system planning, has said DOE funding would provide certainty to members and make interconnections more attractive for developers.

During MISO’s Board Week in March, Johnson said more needs to be done to figure out how DOE funds will intermingle with cost allocation. He joked that the process won’t be as simple as the DOE “cutting a $500 million check, as much as I ask them to.”

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ACORE: MISO Should Retool Market for Resources’ Transition

[EDITOR’S NOTE: A previous version of this article misspelled Michael Goggin’s last name on first reference and incorrectly labeled him as ACORE’s “grid strategies vice president.”]

A new American Council on Renewable Energy (ACORE) report recommends MISO make multiple changes to its markets to take advantage of a shifting resource mix.

Michael Goggin, vice president at Grid Strategies and the report’s author, said during an April 25 webinar that he would like see markets with new design elements maximize optimal dispatch and minimize control room operators’ out-of-market commitments.

Goggin said MISO should improve the accuracy of its market participants’ minimum generation levels and filed ramp rates by tightening their rules. He said the grid operator should ensure submitted generator bid parameters reflect the units’ true flexibility, including ramp rates and start-up times or minimum output limits that aren’t physical but economic in nature. He said bid parameters that underplay a unit’s actual flexibility result in excess payments to slow-moving generation.

“I think a common theme across our recommendations here is to use markets,” he said. “Markets are extremely effective and efficient for aggregating a lot of information, which is what the power system has. In many of these RTOs, you have thousands of generators, millions of customers. … Markets are extremely good for aggregating that information and sending the right price signal to the generator to do what is needed to maintain reliability.”

Goggin said incoming battery storage, which is nearly “perfectly flexible,” has a lot of reliability potential. However, he said MISO’s market is “shortsighted” in that it currently prohibits dispatchable renewable energy from furnishing a range of operational reserves.

“We think this is harming customers because wind and solar resources have extremely flexible capabilities to provide a range of operating reserves,” he said.

Much of MISO’s existing generation is inflexible and can’t be dispatched up and down quickly, Goggin said. He said MISO should make a point to “price inflexibility” and remove uplift and out-of-market payments from inflexible resources, saying a failure to so can harm the resource transition.

“Traditionally, we got used to operating the power system that way, but now that we have new resources that are highly flexible, and you can actually add things like batteries to your existing plant, we think that a lot of the market design that made sense decades ago no longer make sense,” he said.

Goggin said controllable wind and solar resources are “underappreciated.” They’re underused for flexibility services, he said, and left navigating market rules that weren’t designed for them.

“We hear a lot from RTOs fretting about losing so-called flexible resources and talking about the need to directly compensate for flexibility. And that may be true, but I feel like there’s often less thought put into how to get rid of these market features that reward inflexibility,” Sierra Club senior attorney Casey Roberts said.

Roberts said she thinks resources owners understating flexibility in their bid parameters is a pervasive problem and that RTOs should take steps to hold them accountable. She said observing how many thermal resource owners alter their startup times compared to what was on the books before MISO introduced its new availability-based capacity accreditation was “interesting.”

“Several generation owners suddenly discovered they were a lot more flexible than they had previously thought and asked for waivers from those rules so their ‘true’ greater flexibility could be reflected in their capacity accreditation,” she said.

Roberts also said MISO is making an unfortunate choice by disqualifying its wind and solar resources from providing ramping capability. (See MISO Plans to Bar Intermittent Resources from Ramp Capability.)

“This is not based on the technical capabilities of these resources, but rather an inability of MISO’s own software systems to discern whether any resource’s ramp-up capability would actually be deliverable or whether they appear to be available to deliver ramp-up because they’re curtailed due to transmission constraints,” Roberts said. “That results in a situation where MISO has to manually confirm each resource’s availability to deliver ramp up, which it’s willing to do for thermal resources but not for renewable energy simply because there are so many of them it would be an untenable problem.”

That issue illustrates that MISO needs software and transmission upgrades in market updates, she said.

Leeward Renewable Energy’s Emma Nix agreed that RTOs need transmission buildout to support interconnecting inverter-based resources. She said that MISO is entering capacity markets’ next phase considering the daily times that capacity is most needed.

Goggin urged MISO to use a sloped demand curve in its capacity auction and account for simultaneous unavailable capacity caused by widespread generation outages. He said it’s common for much of the generation portfolio to trip offline at the same time during weather events. (See MISO Charts Course on Capacity Auction’s Sloped Demand Curve.)

MISO should add probabilistic forecasting to commit resources and shrink the time it takes to commit resources as close to real-time as possible, he said. MISO can reduce forecasting errors by shortening the time that passes from commitment to output, Goggin said.

He praised real-time, five-minute markets as the most effective means of incenting flexibility. He said energy price caps can sometimes interfere with the market because they can mask the operating day’s riskier periods and can trigger units to prematurely release all available output. He added that higher wholesale market price caps will have “very little” rate impact because most customers will never pay a real-time price.

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FirstEnergy Pressured to Acquire W.Va. Coal Plant

Pressure to purchase and run a West Virginia coal-fired power plant poses financial and political complications for Ohio-based FirstEnergy (NYSE:FE).

Analysts participating in the FirstEnergy’s first-quarter earnings conference call Friday questioned whether the company’s regulated West Virginia subsidiary Monongahela Power would purchase the Pleasants Power Station, a deregulated plant the company previously owned that is now struggling to compete in the PJM market and slated for shutdown on May 31.

The Public Service Commission of West Virginia in December asked FirstEnergy to consider approving Mon Power’s purchase of the 44-year-old, 1,300-MW coal plant, located on the West Virginia side of the Ohio River.

FirstEnergy briefly owned Pleasants after buying the Pennsylvania-based utility Allegheny Energy in 2011. But in 2017 it tried to move ownership and operation of the plant from what had become unregulated Allegheny Energy Supply to regulated Mon Power. FERC blocked the move. (See FirstEnergy Shutting Down Unsold Coal Plant.)

The plant is now owned by Maryland-based Energy Transition and Environmental Management, a company that demolishes old power plants and repurposes the sites. ETEM is leasing the plant to its previous owner, Energy Harbor, which will handle shutdown at the end of this month.

Energy Harbor is the company that emerged from the bankruptcy of FirstEnergy’s power plant subsidy FirstEnergy Solutions.

FirstEnergy agreed to review the request from the PSC, but earlier this spring it asked for a subsidy of $3 million/month to cover operating Pleasants for a year while it continues to evaluate whether to purchase and operate it as a regulated facility. Consumer groups and the state’s consumer advocate are opposing the idea.

FirstEnergy CFO Jon Taylor explained the West Virginia situation to analysts during a review of the company’s rate increase plans pending or planned before utility regulators across its 10 electric distribution companies.

“Mon Power proposed an option to enter into an interim arrangement with Pleasants’ current owner that would keep the plant operational beyond its May 31 deactivation date. This would allow the needed time to do a thorough analysis and evaluation as requested by the West Virginia PSC,” he said.

Taylor said the PSC approved the company’s request for the subsidy earlier in the week.

“We will begin negotiations with the plant’s current owner. If we reach an interim agreement that we believe is in the interest of customers and FirstEnergy, we will submit it to the commission. And if approved, this would allow recovery of associated costs through a surcharge. If we can’t reach an agreement that is in the interest of our customers, we will file an update with the commission,” he said.

A complication is that Mon Power and a second regulated FirstEnergy subsidiary, Potomac Edison, already own two other large coal-fired power plants in the state.

If FirstEnergy approves Mon Power buying Pleasants, the company will likely close one of the other plants, said Taylor. “We don’t see it as a viable option for Mon Power to operate three coal-fired power plants in West Virginia,” he said.

FirstEnergy “is moving forward with efforts to support the energy transition across our footprint,” Taylor told the analysts. “And we remain committed to our climate strategy and our goal to achieve carbon neutrality … by 2050.”

The company is planning to build five solar farms in the state with a total output of 50 MW, he said.

An analyst with KeyBanc asked whether the company will face an “impossible situation” and will “pay a political price” in the state if it does not purchase the Pleasants power plant.

Interim CEO John Somerhalder responded that the company is committed to working closely with the state. Noting that the Pleasants plant is newer and equipped with enhanced environmental controls, the request from the PSC is “a good question that needs to be evaluated,” he said.

Somerhalder’s review of the company’s overall financial performance in the first quarter was equally upbeat.

“Despite record-high temperatures across our footprint this winter, we’re off to a good start in 2023 as we continue positioning FirstEnergy for greater resiliency and growth by strengthening our financial position, enhancing our operations and optimizing the customer experience,” he said.

The company reported first quarter earnings of $292 million ($0.51/share) on revenue of $3.2 billion. That compares with earnings of $288 million a year ($0.51/share) on revenue of $3 billion.

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CARB Adopts Clean Fleets Rule Despite Broad Skepticism

California regulators approved a rule that will ban the sale of diesel trucks in the state starting in 2036, requiring all new medium- and heavy-duty trucks sold to be zero-emission.

The regulation, called Advanced Clean Fleets (ACF), also requires truck fleet operators to start transitioning to zero-emission vehicles beginning on Jan. 1, 2024.

The California Air Resources Board (CARB) voted unanimously on Friday to adopt the regulation.

“This is an absolutely transformative rule to clean our air and mitigate climate change,” CARB Chair Liane Randolph said just before the board’s vote.

But Randolph acknowledged there are challenges in the transition to zero-emission trucks. Some board members, while supporting the regulation, expressed doubts that sufficient infrastructure would be available to support the ZEVs.

“Those challenges aren’t going to be tackled unless we move forward,” Randolph said. “No one is going to build infrastructure in the abstract. So, we need to adopt this rule, move forward, get it going, and work through all of these implementation challenges.”

The agency initially had proposed banning the sale of diesel trucks starting in 2040. But during a hearing on the proposed regulation in October, the board asked to move up the ban to 2036. CARB called the 2036 ban on diesel trucks “a first-in-the-world requirement.”

Timeline Questioned

Critics called the timeline unreasonable.

American Trucking Associations CEO Chris Spear said fleet operators are just getting acquainted with zero-emission trucks. He said they are finding that the vehicles are more expensive than internal-combustion vehicles and that charging and refueling infrastructure is “nonexistent.”

“California is setting unrealistic targets and unachievable timelines that will undoubtedly lead to higher prices for the goods and services delivered to the state and fewer options for consumers,” Spear said in a statement following Friday’s vote.

In response to feedback during the October board meeting, CARB staff revised the regulation to give fleet operators more flexibility in complying with ACF. (See CARB Examining Obstacles on Road to ZEV Fleet Adoption.) The changes were released in March for 15 days of public comment.

But many local governments across the state still objected to the regulation.

The Nevada County Board of Supervisors said in a letter to CARB that ACF doesn’t consider local agency budget constraints. The regulation also doesn’t factor in the time needed to build the infrastructure needed to support the ZEVs, the letter said.

“Electrifying service yards to support an electrified fleet is a much greater undertaking than a simple electricity panel upgrade or some quick trenching in the parking lot,” said the letter, signed by Board of Supervisors Chair Ed Scofield.

CARB member Bill Quirk, who was appointed to the board in January, asked agency staff on Friday about the availability of zero-emission drayage trucks with a range of at least 400 miles. That’s an issue that some speakers raised during public testimony on Thursday.

Heather Arias, CARB’s transportation and toxics division chief, said some hydrogen fuel cell trucks with that range are now available. As for fueling, Arias said, there are two hydrogen stations at San Pedro ports and two more are expected near the Port of Oakland. In addition, the California Energy Commission is considering funding several hydrogen fueling stations throughout the Central Valley.

“Within a year, we anticipate that drayage fleets would be able to buy hydrogen fuel-cell trucks with upwards of a 500-mile range and be able to fuel anywhere from the Port of Oakland all the way down to San Pedro and several spots in between,” Arias said.

Quirk, who owns a hydrogen fuel cell vehicle, noted the difficulties of fueling near his home in the Bay Area. He said the CEC “cannot be depended upon to do this.”

“I’m just not optimistic that the infrastructure’s there, and I think we need to put pressure on the Energy Commission to make sure it is there,” said Quirk, a former state Assemblyman. “And not only that the stations are there, but the hydrogen is there. Because again, these stations run out of hydrogen all the time.”

Board member John Balmes said providing infrastructure to support the ZEVs would be “a huge lift.”

“I’m personally skeptical that we can pull it off,” he said.

Other board members focused on the anticipated benefits of ACF.

Board member Diane Takvorian noted that ACF is expected to generate $26 billion in health savings, as cleaner air leads to fewer premature deaths, emergency room visits, hospitalizations and lost workdays.

“It’s resulting in an amazing number of health benefits,” Takvorian said.

ACF is also expected to reduce cumulative GHG emissions in California by 327 million metric tons from 2024 to 2050, making it a key step toward the state’s goal of reaching carbon neutrality by 2045.

Fleets Covered by ACF

The ACF regulations apply to three categories of fleets: drayage fleets; state and local government fleets; and federal and high-priority fleets. Fleets are considered high-priority if they have 50 or more vehicles or more than $50 million in annual revenue.

The requirements are the most stringent for drayage trucks, the heavy-duty vehicles at ports and railyards that transport cargo. The idea was to prioritize air quality improvements in disadvantaged communities near ports and warehouse districts.

All new trucks added to drayage fleets must be zero-emission starting in 2024, and all drayage trucks must be ZEVs by 2035.

And while operators of other types of fleets have the flexibility to add ZEVs or near-ZEVs, such as plug-in hybrid trucks, to comply with ACF through 2035, the near-ZEV option isn’t available for drayage fleets.

For high-priority fleets, all new trucks must be ZEVs or near-zero-emission starting in 2024.

For state and local fleets, half of new trucks must be ZEVs or near-zero-emission from 2024 to 2026, and all must be ZEVs or near-zero-emission beginning in 2027.

Fleet operators may also request more time to comply under a range of circumstances, such as a delay in ZEV infrastructure construction that’s outside their control. An extension of up to five years may be available if the utility needs more time to bring power to the site.

Fleet operators may also be allowed to buy an internal combustion vehicle if they’re looking to replace a specialty truck for which there’s no ZEV equivalent.

And ACF offers an alternative compliance option in which fleet operators can still buy internal combustion trucks but commit to increasing the percentage of ZEVs in their fleets over time. For light-duty package delivery vehicles, for example, half of the fleet would need to be ZEVs by 2031, followed by a full ZEV requirement in 2035. The alternative compliance option isn’t available to drayage fleets.

Advanced Clean Fleets is a complement to the Advanced Clean Trucks regulation that CARB adopted in 2020. That regulation requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles starting in 2024.

Even with Advanced Clean Trucks and Advanced Clean Fleets, an estimated 480,000 heavy-duty combustion-powered trucks will still be on California roads in 2037, CARB said last year in its State Implementation Plan submitted to the EPA. The agency expects to start work on an additional zero-emission truck measure to address remaining diesel trucks, with a target of board adoption in 2028.

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CenterPoint’s $43B Capex Plan on Track

CenterPoint Energy (NYSE:CNP) navigated high interest rates and milder winter weather to turn in a “tremendous start” to 2023, the company said last week.

“We also have great momentum from the continued execution of our long-term growth strategy through which we have deployed more than $8 billion of capital over the past two years,” CEO David Lesar told financial analysts Thursday.

The Houston-based company reported earnings of $313 million ($0.49/diluted share), compared to $518 million ($0.82/diluted share) for the first quarter of 2022. Last year’s opening quarter included gains from the sale of Energy Transfer common and preferred units and local gas distributors in Arkansas and Oklahoma.

CenterPoint’s adjusted earnings of 50 cents/share beat the Zacks consensus estimate of 48 cents, the 12th straight quarter it has met or exceeded expectations.

The utility said it deployed about $1 billion of the $3.6 billion capital it has planned for the year during the quarter. It has a long-term goal of investing $43 billion of capital through 2030 in its Texas and Indiana footprints.

Legislative and regulatory decisions went CenterPoint’s way during the quarter. Texas issued its state gas company about $1.1 billion of securitization funds related to the extraordinary gas costs it incurred during the February 2021 winter storm. The bonds are not on the utility’s balance sheet.

The Texas Public Utility Commission also approved the recovery of costs incurred during the storm for its leased emergency temporary mobile generation units.

“It highlights the commission’s awareness of the important role of this critical tool can play to help mitigate the number and duration of customer outages during extreme weather events,” Lesar said.

On Wednesday, CenterPoint filed an integrated resource plan (IRP) for its Indiana business that would end its use of the state’s coal by 2027. The company said the proposed plan will save customers nearly $80 million compared to the continued use of coal and will reduce carbon emissions by more than 95% over the next 20 years.

Coal generation currently accounts for 85% of the electricity for the utility’s southwest Indiana customers. By 2030, CenterPoint projects more than 80% of its electricity in the state will be generated by solar and wind, with natural gas providing the rest.

The company plans to convert its last coal plant, F.B. Culley 3, to natural gas by 2027 and maintain its 270-MW capacity. It will also add 200 MW of wind and 200 MW of solar by 2030; another 400 MW of wind resources could be added by 2032.

CenterPoint plans to submit the final IRP to the Indiana Utility Regulatory Commission by June 1, with a response expected next year. The plan is also designed to comply with MISO’s new, more stringent capacity requirements to meet peak energy demand across all four seasons. The company serves 150,000 customers in southwestern Indiana.

CenterPoint’s share price finished the week at $30.47, a gain of 12 cents from Wednesday’s close.

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MISO: Long-range Tx Needed for 369 GW in Interconnections

MISO last week laid out more reasons why it needs a second long-range transmission plan (LRTP) portfolio, saying it will connect several hundred gigawatts of new resources over the next 20 years to avoid reliability crises.

The grid operator expects to add 369 GW of new resources, mostly renewable, by 2042. Even with 103 GW of capacity expected to retire from the existing fleet, MISO will have 466 GW of installed capacity. However, only 202 GW of that capacity is accredited; staff assumes a declining effective load-carrying capability for the renewable additions.

During a teleconference Friday with stakeholders, James Slegers, MISO’s senior expansion planning engineer, said the RTO’s middle-of-the-road, 20-year future scenario shows that it needs transmission capacity to manage resource expansion and increased load.

MISO has three transmission planning futures, ranging from conservative to aggressive. The second LRTP cycle is based on the second future, which assumes all states’ climate goals and members’ integrated resource plans are realized.

Staff have said the second portfolio could cost as much as $30 billion. MISO aims to recommend the portfolio during the first half of 2024. (See MISO Says 2nd LRTP Portfolio Still in Flux.)

Slegers said an energy adequacy analysis indicates risks will be most pronounced during the “twilight hours” on hot summer days, when load is still high, solar has dropped off and wind production is low. He said MISO could find itself needing up to an additional 29 GW of flexible resources over what it has now for those three or four hours in 2042 on the most challenging operating days.

Staff said they expect to connect new types of flexible resources to the system, including green hydrogen, long-duration battery storage, small modular nuclear reactors, and reciprocating internal combustion engines. The RTO forecasts 3 GW of offshore wind farms in the Gulf of Mexico will meet Louisiana’s goal of net-zero carbon emissions by 2050.  

MISO says the second LRTP’s benefits include avoided load-shedding during extreme weather events, less transmission investment, greater access to capacity and meeting decarbonization goals.

Having completed the latest resource expansion forecasts, staff will now build reliability and economic models into the fall meant to identify beneficial projects.

MISO is also considering hosting a Planning Advisory Committee meeting May 31-June 1 to delve into the footprint’s need for future 765-kV and HVDC lines alongside other transmission technologies. Committee leadership has invited stakeholders to prepare presentations.

MISO will host its next LRTP workshop June 5.

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Committee Gives CAISO RTO Bill a Cool Reception

California lawmakers voiced their concerns Wednesday with a bill that could eventually allow CAISO to become an RTO with a governing body independent of the state’s governor and legislature.

Assembly Bill 538, by Assemblymember Christopher Holden, had its first legislative hearing before the Assembly Utilities and Energy Committee, of which Holden is a member and former chair.

Christopher Holden (California Assembly) FI.jpgAssemblyman Christopher Holden | California Assembly

The committee members allowed the bill to move on to the Assembly Appropriations Committee, chaired by Holden, but only after expressing their discomfort with the measure as it is now written and seeking assurances from Holden that he would make changes going forward.  

Chief among their problems with Holden’s measure was the potential lack of legislative oversight of an independent CAISO board. Another was the effect on in-state jobs. Labor unions, which wield strong political clout in California, vehemently oppose the measure because they believe it could lead to generation projects being built in neighboring states.

“We’ve really focused on the issue of the impacts on jobs and bringing the CAISO governance back to the legislature,” Committee Chair Eduardo Garcia said.

The bill remains a work in progress, and Holden has committed to “resolving a lot of the difficult points … that still need some ironing out,” Garcia said. That includes “wanting to have legislative oversight and some type of check-in.”

“To my friends in labor and others who strongly oppose this bill … there will continue to be some conversations,” he said.   

Eduardo Garcia (California Assembly) FI.jpgAssembly Utilities and Energy Committee Chair Eduardo Garcia | California Assembly

CAISO is a public benefit corporation created by the legislature in 1998. The governor appoints its Board of Governors, and the state Senate confirms them. That effectively makes all board members Californians, though it is not expressly required by statute.

CAISO’s one-state governance has been the main sticking point in regionalization efforts. California lawmakers have refused to cede control, and other Western states will not join an RTO controlled by California politicians.

Holden’s prior efforts to expand CAISO governance to include other states in 2017/18 failed because of opposition from his fellow Democrats in the legislature.

Like those efforts, AB 538 lays out a process for CAISO to develop its own proposal for independent governance without requiring legislative approval. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)

“The Independent System Operator’s Board of Governors may develop and submit to the [California] Energy Commission a governance proposal,” it says. “The Independent System Operator shall provide notice and a copy of this submission to the Legislature and the Governor at the same time as it is submitted to the Energy Commission.”

The Energy Commission and the state Air Resources Board would review the governance plan, holding public workshops and providing written comments, the bill says. The commission would then submit the proposal to the governor and legislature, but the measure is silent on whether lawmakers and the governor would have final say.

AB 538 would also require the formation of a Western states committee with an equal number of representatives from states with participating transmission owners in CAISO.

“The representatives from California shall be appointed by the Governor, subject to confirmation by the Senate. The committee shall provide guidance to the Independent System Operator on all matters of interest to more than one state,” it says.

‘Another RTO’

Committee members and opponents of the measure told Holden they could not accept the lack of legislative oversight, the vague role of the Western states committee or the idea that California, which makes up about a third of the load in the Western Interconnection, might have the same number of votes as less-populated states.

Matthew Friedman (California Assembly) FI.jpgMatthew Freedman, TURN | California Assembly

“Under this bill, California would give up meaningful control over the California ISO, marginalize the role of its elected officials and state regulators and invite greater involvement by the federal government and hostile private interests throughout the West,” said Matthew Freedman, staff attorney with The Utility Reform Network, a ratepayer advocacy group that opposes the bill.

“If this bill passes, it’s the last bill the legislature will ever consider relating to wholesale electricity markets,” Freedman said. “The creation of a multistate RTO divests the legislature from having any ongoing role, and, in fact, you’re being asked to make yourselves and state agencies and the governor completely irrelevant.”

Proponents of the measure said it would further the 100% clean energy goals of California and other states in the West, reduce costs for ratepayers and promote reliability through centralized dispatch operations.

Jan Smutny-Jones (California Assembly) FI.jpgJan Smutny-Jones, Independent Energy Producers Association | California Assembly

They noted that circumstances have changed substantially in the five years since Holden’s prior attempts to make CAISO a multistate RTO.

The West has experienced strained supply during extreme weather, including blackouts and near misses the past three summers in California. More states, cities and utilities have adopted 100% clean energy goals like California’s, requiring new transmission to move wind and solar power long distances. And two states, Nevada and Colorado, enacted requirements that their major transmission owners join RTOs by 2030.

They also noted that SPP is planning to establish a Western version of its Eastern Interconnection RTO, called RTO West.

“There is another RTO forming in the West, and you need to be aware of this,” Jan Smutny-Jones, CEO of the Independent Energy Producers Association, told committee members. “It’s called the Southwest Power Pool, out of Little Rock, Arkansas. They’re aggressively working in our neighboring states to try to get them to join their RTO. This will be a different RTO than the one that would be built by the ISO.”

SPP also has the Western Energy Imbalance Service and is developing Markets+, a program with a day-ahead market. The development of Markets+ and an SPP RTO could erode CAISO’s successful Western Energy Imbalance Market, because participants in SPP’s markets will not want to be in both, Smutny-Jones said.

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Texas RE Sees Opportunity in Cold Weather Standards

NERC’s new cold weather standards give utilities considerable freedom in implementation, which is both an opportunity and a danger, attendees at a workshop hosted by the Texas Reliability Entity heard Thursday.

Speaking at the regional entity’s Spring Standards, Security and Reliability Workshop, Mario de la Garza, Texas RE’s manager of operations and planning compliance monitoring, pointed out that EOP-011-2, which took effect earlier this month after FERC approved it following the February 2021 winter storm, specifies only that registered entities prepare for “cold weather” rather than specific temperatures or conditions. (See FERC Approves Cold Weather Standards.)

This is deliberate, he said, observing that utilities in different areas will likely have very different ideas of what constitutes “cold weather.”

To illustrate this difference, he conducted a survey for participants to provide their definitions of “cold.” The seemingly simple question garnered a wide range of responses: The most popular answer was simply “below freezing,” but one said “not hot or warm,” while another believed only “20s [F] for [an] extended period of time” qualified, and one said “cold” meant a temperature “that impacts equipment.”

Defininition of Cold Survey (Texas RE) Alt FI.jpgAttendees gave a wide variety of responses when asked for their definition of the word “cold.” | Texas RE

“My definition of cold is 40 degrees; that’s where I need to put my jacket on,” Garza said. “But that’s clearly not the same definition for [someone] who lives on the [Texas] Panhandle.”

If the definition of cold varied so much in just one room, Garza continued, the difference must be even greater between the service areas of different utilities — or even within the territory of a single large utility. This is why the standard drafting team that created the cold weather standards made the definition so broad, he said: to give individual utilities the flexibility to define cold weather, and their response to it, according to the circumstances they face rather than imposing definitions that may not make sense for everyone.

Garza acknowledged that this freedom also creates a responsibility for utilities to be proactive in setting parameters for the applicability of EOP-011-2 and its successor EOP-011-3, which is set to take effect in October next year. (See FERC Denies Rehearing of Cold Weather Standard.) The standards’ requirements include the creation of cold weather plans, and the freedom they provide means utilities must be thorough when setting the “trigger points” at which their plans take effect.

Garza recommended that once utilities have a plan in place, they make sure all relevant personnel are properly trained. He joked that auditors at Texas RE are “big fans [of] checklists” — especially ones that are completed.

“When we get a filled checklist for a specific project, that shows us that certain activities were performed [and] gives us some assurance that things were done … in respect to the matter,” Garza said. “So we highly encourage [you to], along with your plan, have a checklist to make sure that individuals who are a part of your plan are doing tasks in a specific order … that they are responsible for.”

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ISO-NE Stakeholders OK DER Aggregation Plans, Generator Relief

The NEPOOL Markets Committee on Tuesday approved ISO-NE’s proposed compliance filing to FERC on distributed energy resource aggregation but rejected the RTO’s concerns in backing LS Power’s bid to save Ocean State Power’s (OSP) capacity supply obligation (CSO).

The committee overwhelmingly supported tariff changes to allow the gas-fired combined cycle plant to unwind a 64-MW capacity increase while maintaining its CSO for its existing 270 MW.

In Forward Capacity Auction 15, Ocean State Power cleared as a “repowering” to increase its output to 334 MW, a 24% increase, and was awarded a seven-year rate lock at $3.98/kW-month.

LS Power’s Dilemma

Since winning the award, however, LS Power has become concerned it may not be able to complete the upgrade economically — and by the RTO’s June 1, 2026 deadline for commercial operation — because of rising prices and supply chain challenges.

The company said it was surprised to learn that failing to add the incremental capacity as promised could cause it to lose its CSO for its existing capacity. “Under the ISO’s interpretation of the tariff, there is no way for a ‘repowered’ resource to unwind future [Forward Capacity Market] commitments, leading to an unexpected and nonsensical ‘bet-the-plant’ situation,” it said in a presentation by Ben Griffiths, director of New England market policy. “If OSP had cleared as greenfield new or as a minor uprate, we would not be here today: The tariff is unambiguous in the ability of these resources to shed incremental obligations.”

The company’s proposed tariff change would allow it to cancel the 64 MW of incremental capacity while ensuring the RTO retains 270 MW of capacity. The plant, in Burrillville, R.I., has connections to two interstate pipelines and 2 million gallons of on-site oil storage, enough for three days at full output.

The company said it would accept the same penalties that would apply if a minor uprate (less than 20%) or a greenfield project were terminated: forfeiture of the price lock and $2 million in financial assurance on the 64 MW that OSP cleared in FCAs 15 to 17.

Southeast New England customers would avoid having to pay $3.98/kW-month for 334 MW of capacity in FCAs 16 to 21, LS Power said. Because the two most recent auctions cleared around $2.60/kW-month, the savings would be about $15 million in FCAs 16 and 17, it said. Generators would benefit from the elimination of 64 MW of capacity from the supply stack in future auctions.

The company said the current repowering provisions were intended to allow existing capacity to obtain price locks, which are no longer permitted.

It said market power concerns in current rules were over the ability of only new resources to set the clearing price. Now that existing resources can set clearing prices, “concerns about toggling between new/existing do not matter in [the] same way,” it said.

The company said the 20% threshold for repowering is “largely arbitrary” for market mitigation. “Our 64-MW ‘repowering’ … would have been considered an uprate if OSP had a starting capacity of 320 MW instead of 270 MW,” it said.

ISO-NE’s Internal Market Monitor issued a memo saying it needs more time to vet the design changes and market power considerations.

“We do think taking a fresh look at the repowering rules in the tariff is a good idea, but we have a number of concerns with the proposed rule changes and the short evaluation time frame. In summary, the evaluation will need to assess incentives to limit the exercise of market power and gaming, and provide a clear and commensurate remedy if a participant is unable to perform on its repowering obligation,” the Monitor said.

The current rules were “intended to act as a strong deterrent to potentially setting a higher clearing price and securing a multiyear revenue stream, and subsequently toggling back to the original status,” the Monitor added. “This proposal does not factor in the potential market harm caused by the clearing of the repowering resource in the FCA, and may not adequately incentivize market participants to deliver on obligations obtained in the auction.”

Andrew Gillespie, the RTO’s director of market development, also weighed in with a separate memo.

Gillespie said the RTO’s primary concern is “the incentive and appropriate compensation problems created if existing capacity effectively participates in the FCA as new capacity and sets the FCA clearing price.” He noted that new capacity offers are subject only to buyer-side mitigation, with no downward mitigation.

Despite the RTO’s concerns, LS Power’s motion passed the committee with 83% of the vote, with unanimous support (excluding abstentions) from the Generation, Transmission, Supplier, Alternative Resources and End User sectors. The Publicly Owned Entity sector was unanimous in opposition.

The proposal will next be considered by the Participants Committee. But it’s far from certain that FERC would approve it, given the IMM’s concern that it would amount to retroactive ratemaking.

Compliance Filing on DER Aggregation

The committee also voted overwhelmingly in support of the RTO’s proposed response to FERC’s March 1 order requiring changes to its rules for DER aggregations under Order 2222 (ER22-983). (See FERC Gives ISO-NE Homework on Order 2222.)

Renewable energy groups had criticized ISO-NE for not going far enough to remove barriers for DERs to participate in wholesale markets, as required by Order 2222.

The commission agreed, saying the RTO failed to show that its proposed energy and ancillary services market participation models accommodate the physical and operational characteristics of behind-the-meter DERs. It flagged ISO-NE’s choice to require measurement of most behind-the-meter DERs at the retail delivery point, rather than allowing sub-metering.

Henry Yoshimura, director of demand resource strategy, presented the new filing, which the RTO plans to submit by May 9. The filing addresses six issues raised by FERC.

The RTO drafted tariff revisions for four items:

  • small utility opt-in requirement;
  • existing rules requiring market participants providing energy withdrawal service to register a load asset;
  • dispute resolution rules; and
  • applying nonperformance penalties to aggregations.

However, ISO-NE will provide additional explanation defending its proposed metering configuration rules. In addition the RTO and several of its utilities filed for rehearing on the sixth issue, rules governing the submission of metering data by DER aggregators.

FERC ordered ISO-NE to revise its tariff to designate the DER aggregator as the entity responsible for providing required metering information to the RTO.

Yoshimura said FERC’s requirement would run afoul of state policies that make host utilities responsible for providing metering services to all energy market loads and resources in the region. He said compliance would require modification of current agreements and costly changes to metering infrastructure and processes.

“Additional design elements would be needed to avoid costly delays in energy market settlement from potential data transmission errors and energy balance reporting, and to prevent double-counting of services,” the RTO added. “DER aggregators would need to install and operate costly and redundant metering and communications systems that no other energy market participant is required to install and operate.”

Any alternative metering requirements would depend on the commission’s final orders concerning acceptable metering configurations and the rehearing request on submission of metering data.

The RTO’s motion passed with 78.6% in favor, with unanimous support from the Generation, Transmission and Publicly Owned Entity sectors. The Supplier sector was mostly in favor, while Alternative Resources was split, and End Users were mostly opposed.

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Nevada Bill Would Require Gas Company Efficiency, GHG Plans

Nevada natural gas utilities would be required to file a plan every three years, similar to the integrated resource plans filed by electric utilities, under a bill intended to make natural gas planning more transparent.

Senate Bill 281, by state Sen. Rochelle Nguyen (D), would require natural gas utilities to detail the amount of greenhouse gas reductions they would achieve and how they would promote energy efficiency and conservation.

The plan would assess the reliability of gas pipelines and spell out any significant operational or capital requirements for the next three years.

The Public Utilities Commission of Nevada (PUCN) would hold a public hearing on the plan and vote on whether to accept it. The first plan would be due on Oct. 1, 2025.

Under current law, a natural gas utility must file an informational report with PUCN each year, discussing natural gas demand, costs related to providing gas service and planned gas acquisitions. The reports don’t go through a hearing process.

“Senate Bill 281 increases transparency around natural gas infrastructure investments and provides an appropriate venue for all stakeholders to participate in and provide feedback to utility regulators on the need for future natural gas investments,” Nguyen said during a hearing on the bill this month before the Senate Growth and Infrastructure Committee.

In 2021, the PUCN opened an investigatory docket on the future of natural gas in Nevada. Stakeholders made it clear during that process that they’d like natural gas utilities to face planning requirements similar to those for electric utilities, Nguyen said.

The committee passed SB281 on April 12. The bill is exempt from an April 25 deadline for bills to pass out of their house of origin.

Supporters include Southwest Gas, the largest distributor of natural gas in Nevada, serving about 792,000 customers.

“We think this is a good bill. We think it’s a fair process. We’ve done a lot of work on it,” Scott Leedom, director of public affairs for Southwest Gas, said during the committee hearing.

Union representatives said the bill would promote transparency and create jobs.

Representatives of Chispa Nevada, a program of the League of Conservation Voters, said the bill would help combat soaring gas rates.

“SB281 is an important step to hold Southwest Gas accountable for current and future rate increases as well as the impact of their investments on the environment,” Chispa National Director Estefany Carrasco-Gonzalez said in a letter to the committee.

Previous Bill Failed

Leedom of Southwest Gas also discussed SB281 this month during a joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body in Incline Village, Nevada. Leedom was a panelist during a session on natural gas planning.

SB281 follows another natural gas planning bill in Nevada, Assembly Bill 380 by Assemblywoman Lesley Cohen (D), which died in its first committee during the 2021 legislative session. Southwest Gas lobbied against the bill, saying it “effectively bans natural gas.” (See Bill Would Tighten Oversight for Nevada Gas Providers.)

Leedom said AB380 went beyond implementing a planning process by including measures to promote a transition away from commercial and residential use of natural gas. It also would have blocked the utility’s expansion into new areas for economic development purposes.

“We are open to a planning process — just not one that plans to our ultimate demise,” Leedom said.

After AB380 failed, Southwest Gas began working with Sen. Chris Brooks (D) on a bill creating a natural gas planning process, similar to the integrated resource plans required for electric utilities.

But Brooks, whom Leedom described as a central figure in Nevada energy policy, resigned from the Senate last year to take a job in private industry. The Clark County Commission appointed Nguyen to fill the vacant seat. Nguyen agreed to keep working on the bill.

Gas Infrastructure Bill

In this year’s legislative session, another natural gas bill has died. SB116 by Sen. Skip Daly (D) would have allowed natural gas utilities to file a gas infrastructure modernization plan for approval with the PUCN. The plan would cover infrastructure projects proposed for the next five years.

The utility could then recover its infrastructure costs through a separate monthly rate charged to customers.

Daly said during a hearing before the Senate Growth and Infrastructure Committee that the bill was intended to address the potential degradation of certain types of pipe. The U.S. Department of Transportation issued an advisory about the degradation, which it said has been seen in certain pipelines installed between 1978 and 1999 in the southwestern U.S. and potentially could be more widespread.

Opponents of the bill included the Nevada Conservation League, which said utilities already have an effective process for replacing old or leaky pipes. The League called the bill “a step in the wrong direction for ratepayers and climate goals.”

“SB116 would lock in decades of continued reliance on fossil fuels, even as new, more efficient technologies become available, while guaranteeing Southwest Gas continues to collect a check,” the League said in a news release.

After holding a hearing on SB116, the Senate Growth and Infrastructure Committee took no action on it. The bill missed the April 14 deadline for committee approval in the house of origin and is now dead.