CHICAGO — The first annual meeting of the Mid-America Regulatory Conference (MARC) in two years focused on transmission needs in the middle of the country necessary for a fast-changing energy landscape.
Advanced Power Alliance’s senior vice president of markets and infrastructure Steve Gaw said both seams planning and interconnection queues deserve more attention in MISO and SPP. He said SPP’s planning futures are not realistic enough, as evidenced by its clogged interconnection queue.
“Transmission takes a long time to build. We’ve got a lot of work to do on that front. I think we have a good foundation, and I think we need to build on what’s working,” Gaw said during a Wednesday panel discussion.
ITC Holdings Chief Business Officer Krista Tanner said the two RTOs have come a long way on their seams planning.
“Two, three years ago, there was no communication on that. And now look,” she said, offering the caveat that MISO and SPP must still settle on a cost allocation for their joint targeted interconnection queue (JTIQ) planning study. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)
Tanner said the grid operators must do more planning to clear their queues. She said SPP’s five-year backlog is evidence that it’s not functioning well. However, she called the JTIQ work “a heck of a good start.”
“I’m not sure it can happen fast enough,” said Usha-Maria Turner, director of environmental, federal and RTO policy at Oklahoma Gas and Electric. “We’ll make progress on the current queue backlog, but … we’re seeing more and more renewables come into the queue, and that queue just has to get faster.”
Gaw called for a minimum transfer capability between RTOs and ISOs to maintain resource adequacy. He said the transmission that helped MISO and SPP successfully navigate the February 2021 winter storm wasn’t originally built to help the region’s punishing winter storms.
“A lot of the reason for those lines was to move renewable energy from the west to east, but because we had those lines, we were able to keep the lights on,” he said.
Tanner said the 16 lines in MISO’s 2011 Multi-Value Project portfolio were at capacity “the moment they came online.” She said MISO and its members have since miscalculated baseload retirements, load growth and the pace of renewable energy growth in their transmission planning.
“Everything was underestimated,” she said.
Tanner said though MISO’s $10 billion long-range transmission plan seems expensive, February 2021’s winter storm racked up a few hundred billion in costs in just over a week.
Tanner also zinged FERC’s Order 1000 as dysfunctional. She said ITC hasn’t bid on project under the order in years. She characterized the rulemaking as “a race to the bottom.”
“I think the good news is more people are recognizing that … it’s not saving customers money, it’s adding a lot of delay and then there’s litigation,” Tanner said.
Christie Urges States to Lean in on NOPR
FERC Commissioner Mark Christie, during his June 20 keynote address, encouraged state commissions to weigh in on the commission’s notice of proposed rulemaking on transmission planning and cost allocation. He reminded state staff that the “P” in NOPR stands for “proposed” and said the ruling isn’t final yet.
“It mandates the planning on a long-term horizon, but it doesn’t mandate the outcomes,” he said of the NOPR.
Christie said state regulators are poised to know what’s best for their customers.
“If we’re going to mandate billions worth of policy-driven transmission projects in the RTOs largely driven by state policies … [state regulators’] agreement ought to be sought on both the planning criteria and the cost allocation,” he said.
Christie said the NOPR stands to “formalize” states’ role in transmission planning and gives them “maximum creative and flexibility.”
“There’s no one I trust more than state regulators on making sure that projects are in the public interest and transmission expenditures are properly spent,” he said.
Christie also said state regulators, already squeezed for resources by the energy transition, must pay attention to planning. He said transmission investments are poised to explode.
“That transmission component in retail rates is getting bigger and bigger and bigger,” he said. “That component is not small anymore. It’s one of the fastest-growing components of people’s bills. It’s a challenge [to be involved], but you’re either going to be a part of it, or something that’s going to be done to you and your consumers.”
New Mexico regulators have released a draft rule that would set CO2 emission limits for coal-fired power plants, restrictions that raise questions about the future of the San Juan Generating Station.
The New Mexico Environment Department (NMED) released the draft rule on June 15 and opened an informal comment period that runs through June 29.
The proposed rule would set a limit for CO2 emissions of 1,100 pounds per MWh on a 12-month rolling average basis. Owners or operators would be required to develop a monitoring plan, install emissions monitoring systems and submit electronic reports each quarter.
The rule would take effect on Jan. 1, 2023. Comments may be submitted here under Energy Transition Act rulemaking.
SJGS Implications
Currently, the rule would apply to only one facility in the state: the San Juan Generating Station (SJGS).
The other coal-fired plant still operating in New Mexico is the Four Corners Generating Station, which Arizona Public Service runs. The facility is on tribal land, where NMED and the state Environmental Improvement Board don’t have jurisdiction.
NMED isn’t aware of any plans to build a coal-fired plant in the state, department spokesman Matthew Maez told NetZero Insider.
The city of Farmington and Enchant Energy are partnering to acquire the facility and keep it running as a coal-fired power plant, using carbon capture and storage technology to reduce emissions.
But how soon the carbon capture technology would be in place is unclear. And Enchant might want to operate the coal plant without carbon capture for a while.
“The options for how to operate the plant for a period of time upon ownership transfer are being worked through,” Enchant Energy CEO Cindy Crane said in a written statement provided to NetZero Insider. “Enchant will be working closely with the New Mexico Environmental Department to ensure compliance obligations are met.”
The company originally planned to start construction at SJGS in early 2021 and have the plant running with carbon capture in place by January 2023, according to a hearing brief prepared for the New Mexico Legislative Finance Committee last year. But the project had fallen behind schedule at that time and it’s not clear when construction might start.
Enchant also said previously that it planned to operate the plant without carbon capture for two-and-a-half years, according to the brief, written by a fiscal analyst for the legislative committee.
Transitioning from Coal
NMED’s proposed rule is a mandate of the Energy Transition Act, or Senate Bill 489, which Gov. Michelle Lujan Grisham signed into law in 2019. The act sets statewide renewable energy standards and establishes a pathway for a transition away from coal.
The act requires the Environmental Improvement Board to promulgate a regulation limiting coal plant CO2 emissions to 1,100 pounds per MWh starting Jan. 1, 2023. A fiscal impact report for the Energy Transition Act states that the emissions limit “effectively ensures that [SJGS] could not operate as a coal-fired generation facility after 2023.”
Crane at Enchant said SJGS will be fully compliant with the standards when the carbon capture project is finished.
And before then: “Enchant Energy is working on a transition plan for interim compliance as the carbon capture facility is being built with the New Mexico Environment Department,” Crane said.
SJGS would be the first project for Enchant. The company says on its website that its technology would capture 95% of carbon emissions, making SJGS the lowest-emitting coal plant in the world.
Enchant’s partners on the project include Mitsubishi Heavy Industries America, Sargent & Lundy, and Kiewit Power Constructors Co.
Project Timeline
Crane provided an update on the timeline for the project. She said a front-end engineering and design (FEED) study is being finalized and will be filed with the DOE by the end of this month.
After working with DOE to answer questions, Enchant and its partners will file a final FEED report by Sept. 30. The company is aiming to have an engineering, procurement and construction contract and an execution schedule in place by the end of this year.
Enchant expects to be in discussions with financing parties in the fourth quarter of 2022.
Also yet to be finalized are the financial terms between Enchant and the city of Farmington for the SJGS. The city, which has a 5% stake in the facility, will acquire the remainder after PNM wraps up operations on Sept. 30.
The city then plans to transfer 95% ownership to Enchant. Crane said terms of the transaction are still being worked out and are currently confidential.
Following the ownership transfer, Enchant plans to invest about $150 million for deferred maintenance and replacement of a cooling tower, Crane said.
CHICAGO — The Mid-America Regulatory Conference’s (MARC) annual meeting last week bore the tagline “Building the New Normal” with themes that ranged from climate justice and workforce diversity to FERC Order 2222 and the ongoing solar panel investigation.
During a June 20 panel, PricewaterhouseCoopers partner Dennis Curtis said some utilities’ zero-carbon goals are “aspirational” while others are “grounded in lots of process and data.” He said some pilot projects now in their infancy will no doubt be the technology relied upon in 2050 by a zero-carbon industry.
“We cannot do this work at any cost,” Reed Smith partner and former FERC commissioner Colette Honorable said of the clean energy transition. She said the shift cannot be “painted with a broad brush” and must account for customer affordability, particularly for underserved minority and low-income communities.
“We can’t pull out the rug from under people. This has to be thoughtful,” she said. Honorable reminded the audience that communities across the country are currently strapped trying to budget gasoline, groceries, medicine and gas bills alongside their electric bills.
The transition must also be navigated against more ubiquitous severe weather events, she said. “They have names we’ve never heard of and temperatures we’ve never seen.”
Case in point: the MARC meeting was held amid record-tying temperatures in Chicago. Wednesday’s high of 101 degrees Fahrenheit matched the previous record set in 1995.
Julia Friedman, Oracle Utilities’ director of regulatory affairs, said the pandemic and ensuing inflation means that more customers are making other sacrifices to pay their energy bills.
Friedman said more efficiency and demand measures on the residential customer side are necessary and can be more powerful than simply decarbonizing the supply side. She said her company’s research shows that residential customers’ actions can cut the equivalent of 130 coal plants’ carbon emissions output by 2040.
“There’s still so much efficiency to be had,” Friedman said. “When you have at scale, millions of customers taking action, that’s very meaningful, and that has to be part of the conversation.”
Honorable, an independent director for Southern Co., said she recently attended the utility’s shareholder meeting where multiple individuals owning just one share apiece stood to speak about the importance of climate goals.
“These are not decisions that companies are making because of large investors,” Honorable said. She added that “we need so much more transmission” to integrate clean energy.
ComEd CEO Gil Quiniones said utilities must plan the grid for the future climate, not today’s. He said the energy system should not be unevenly split between the “haves” and the “have nots.”
“We have to extend the grid into our customers’ homes,” Quiniones said.
Illinois Speaker of the House Chris Welch said the state’s bipartisan Clean Energy Jobs Act (CEJA) comes at a time when other states are neglecting to have honest conversations about climate change.
He said the law is the nation’s most equitable climate legislation and will positively impact Illinois for “years to come, decades to come.” He pointed out the legislation is supported by both environmental and labor groups.
“That was damn near impossible,” Welch said Wednesday morning. “We’re a leader in this country, in the Midwest … American can and should be a fierce leader in this arena.”
Illinois Commerce Commission Chairman Carrie Zalewski said she thinks of her life as “before CEJA and after CEJA.” She said the commission is focused on “huge dockets” to implement the bill.
Zalewski said her concern for the next five years is “minding the gap,” as MISO executives often say. She said that means overseeing the clean-energy transition reliably, managing ever-higher energy costs, and solving MISO’s capacity shortfall. Zalewski said she’s currently focusing on getting power from capacity-flush PJM’s lower-priced northern Illinois territory downstate to MISO’s southern Illinois footprint.
Order 2222 Will Boost Reserves
Katharine McCormick, the Illinois commission’s assistant director of policy, said FERC’s Order 2222, which opens wholesale RTO and ISO markets to distributed energy resource aggregators, might help MISO’s current 1.2-GW capacity shortfall in its Midwest region, which includes downstate Illinois.
MISO Deputy General Counsel Tim Caister said the implementation plan reflects its current technological limitations. He said a new market software platform needs to be in place before aggregators can participate in the RTO’s markets. MISO also needs more technology, secure communications channels, and a comprehensive review process before aggregations can provide wholesale supply, Caister said.
“We’re moving from a static to a dynamic environment,” he said.
Solar Investigation Slows Development
A panel discussion touched on the U.S. Department of Commerce’s March announcement that it is investigating some Asian solar module manufacturers for circumventing tariffs imposed on China in 2012.
NextEra Energy’s Anthony Pedroni said the investigation is setting solar developers back by upwards of six months. “The damage has been done in the near term,” he said. “Ships literally turned around and went back to their ports.”
Pedroni said the administration’s two-year pause on new tariffs stands to help projects already in development, but future projects need economic certainty and long-term investment signals. He said a decade of the “hammer” of anti-dumping tariffs has done little to spur domestic solar manufacturing.
“If the goal has been manufacturing, it’s not working … We just have outsourced this particular industry to the world,” he said.
He also said President Biden’s use of the Defense Production Act to accelerate domestic production of solar panels requires at least a 24-month lead time.
“[The] worst outcome is project failure,” Pedroni said. He said he was hopeful that the investigation’s results will be a “blip,” albeit a “damaging and expensive blip.”
Making Do with a Leaner Workforce
Panelists contemplated how energy companies and organizations can manage with a shrunken available workforce.
“There were years when people were banging down the doors to come work for us,” Southern Co. Gas Vice President of Human Resources Lindsay Hill said. “Our mindset around work has completely changed.”
With more jobs available than total workers, Hill said, employees will now leave a premier utility “for a dollar more an hour.”
She said that during the pandemic, she was able to drive her children to school for the first time ever because she was working from home. She said the emphasis on flexibility is a holdover from the pandemic.
Hill reminded audience members that the mid-century’s workforce “is sitting in third grade right now.”
“We have to get into elementary schools,” she said. “We want to expose people as early as we can that the energy industry is an option … It might not be as sexy, the utility industry … but it is very stable.”
Hispanics in Energy CEO Jose Perez said Hispanics often lack the higher education necessary to become involved in the energy industry. He said he believes the country could use a development track to get more Hispanics involved in energy careers, facilitated in part by state commissions.
Perez also said a relaxation of the industry’s drug policies, especially concerning marijuana, can help ease the employee shortage.
Jeanine Otte, director of workforce development for equal access nonprofit Elevate Energy, said her company will recruit for organizations that deal with people who have been affected by the criminal justice system. She said her team offers stipends that include transportation to work.
Zalewski said with about a quarter of American adults having some brush with the criminal justice system, it’s worth companies rethinking some hiring policies. She said it’s simply “the larger reality of the system in which we work.”
Panel Debates Weather, Fuel Procurement
As is the case with most regulatory conferences these days, a panel revisited the 2021 February winter storm that froze much of the Southwest and almost brought the Texas grid to its knees.
Texas commissioner Will McAdams said “as painful as it is,” it’s useful to revisit ERCOT’s near-grid collapse during the storm. “Our system did not return to normal for five days,” McAdams said during a June 20 panel discussion. (See Texas Lawmakers Dig into Power Outages.)
McAdams called the failure to plan for emergencies and communicate during the storm Texas’s “own 9/11.” He said the Public Utility Commission has taken “drastic” steps since then. “We’ve taken a lot of regulatory actions in a short amount of time.”
McAdams said ERCOT has almost doubled its amount of ancillary service capability since the winter storm. He said with an increasing amount of renewable penetration on the system, ancillary services are only going to become more important for the state’s standalone interconnection.
“Due to our islanded status, we experience ramping phenomena more than others,” he said.
McAdams said the commission is attempting to “crack the code” of which loads are too critical for service interruptions.
Allen Fore, vice president of public affairs for Kinder Morgan, said expanding natural gas pipelines and storage should help limit the fallout from weather events, but development and permitting remains a “nightmare.”
“One thing we know is that memories fade over time,” he said. “As the crisis fades into memory, the political will fades.”
Fore said to build natural gas infrastructure, developers need long-term secure contracts from credit-worthy companies, something that’s not presently happening.
“We’re not going to build anything and hope somebody will use it,” he said. “We have to have the customer will, which ultimately is the political will.”
Luke Wiles, Enel Green Power’s senior hydrogen strategist, said hydrogen can become a deployable and dispatchable resource when renewable generation wanes.
“Batteries are good for short-term fluctuations,” he said, explaining that batteries struggle to provide a good backup when renewable output slumps for days at a time.
“Hydrogen, on the other hand is a good backup because it can be stored indefinitely … It can repower the grid with clean fuel [for] a longer duration,” Wiles said.
NARUC Workshop Eyes Future Technologies
Following the MARC meeting, the National Association of Regulatory Utility Commissioners convened for a workshop to discuss what technologies might be needed as fossil plants announce retirement.
Experts said investments in carbon capture and storage, pollution controls, and using coal waste will be necessary to prolong the operational lives of coal plants in the face of climate concerns.
Jacquie Fidler, vice president of environmental sustainability at coal-miner CONSOL Energy, said her company is contemplating the development of a 300-MW waste coal and biomass plant near its Pennsylvania Mining Complex.
“This project will not advance unless we can achieve net negative CO2 emissions,” she said. CONSOL will decide in the coming months whether to move forward with the plant and is working through whether the plant is feasible for commercial operation, Fidler said.
SPP Director of State Regulatory Policy Talina Mathews said carbon capture will be key going forward because fossil units, along with nuclear units, will be necessary for some time. She also said lost tax dollars from retiring plants have “tremendous” negative economic effects on their host communities.
Doug Scott, vice president of strategic initiatives at the Great Plains Institute, said last year’s Storing CO2 And Lowering Emissions Act passed by Congress should result in larger capacity pipelines for CO2 transport. He said the larger pipelines make sense as future carbon sequestration picks up, noting he employed a similar strategy for water lines when he served as mayor of Rockford, Ill.
ARLINGTON, Va. — Time is running out to build the infrastructure needed to meet climate challenges, transmission planners, generation developers and others warned last week.
“The things that we have done well are pretty modest. We’re not seeing steep changes,” Liza Reed, the Niskanen Center’s electricity transmission research manager for climate policy, said in one of many related discussions during Infocast’s Transmission & Interconnection Summit, held June 20-22 at the Hilton Crystal City hotel. “We’ve been talking about backbone [transmission] for decades — I mean decades. So, it’s not even new. … That conversation just really needs to mature very quickly.”
It’s inaccurate to describe the challenge of matching generation and transmission as a “chicken and egg” dilemma, said Joseph Rand, senior scientific engineering associate for the Lawrence Berkeley National Laboratory’s Electricity Markets and Policy Group. “When we look at the interconnection queues, we already have 1,400 GW — not megawatts, gigawatts — that’s ready to interconnect to our system now. … It’s not, ‘If we build it, they will come.’ They’re waiting for us to build it.”
“In the planning world, 2030 is tomorrow — and 2040 is the day after,” said Himali Parmar, vice president of energy advisory services, interconnection and transmission at ICF International.
“Lawrence Berkeley National Labs has this great graph that shows all the different RTOs and compares the [renewable portfolio standards]. And it shows that New York and ISO New England have the greatest need to bring renewables onto their grids and are bringing the least on,” said Sarah Bresolin, director of government and regulatory affairs and wholesale markets policy for ENGIE North America.
But it wasn’t all doom and gloom among the hundreds who attended the conference. FERC’s April Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17) and its June 16 NOPR to unclog interconnection queues (RM22-14) won mostly positive reviews.
“We’ve talked about a lot of problems, and I wouldn’t want to leave this panel thinking that there aren’t opportunities,” said Bresolin.
Planning Models not Proactive
Jay Caspary, vice president of consultancy Grid Strategies, said FERC was right to call for proactive, scenario-based transmission planning in the April rulemaking.
“It’s going to take decades to build the grid of the future, so we need to think about what’s the resource mix going to be, and that’s above and beyond the known knowns. We know what units are going to retire in the next few years and know what generators are coming online. But the planning, the models [and] the analyses don’t reflect the commitments that have been made by utilities to get to zero carbon by 2040,” he said. “If you look at planning models now looking out five to 10 years in the future, there’s probably very little electrification in there. And don’t we all really think that electrification is coming in terms of transportation or buildings and industrial processes?
“We need to think strategically about what this grid needs to do … to share resources across time zones,” added Caspary, a former SPP planner. “We need a grid that’s bigger than the weather patterns and storms, so that we can move energy and capacity to keep the lights on. And we need studies where everybody’s involved in how we’re going to … decide what the right metrics are to quantify the benefits. I think that will be a big challenge for us, but I’m sure we’re up for that. I mean, we put a man on the moon.”
Arash Ghodsian, senior director of transmission and policy for EDF Renewables, said FERC should “bifurcate” transmission planning and cost allocation to prevent cost issues from short-circuiting planning.
Johnny Casana, North American strategy director for wind and solar developer Pattern Energy, said dealing with that lag in the Eastern Interconnection doesn’t compare to the challenges of the Western Interconnection.
“I would rather have cost allocation be a hurdle at the end rather than at the beginning of the process,” he said. RTOs should “not let cost allocation discussions stop them from planning.”
Ghodsian also said he hopes FERC’s interconnection rulemaking will ensure the rest of the country adopts best practices, similar to those in MISO. The RTO’s interconnection rules are “three to four years ahead” of its neighbors SPP and PJM, “so there’s always going to be some sort of a lag between all three neighbors,” he said.
“There’s 38 balancing authorities in the West, and they are not integrated, certainly not for transmission planning; not for planning capacity shortfalls that are driven by extreme weather events for their entire region,” he said. “There’s some great studies that have come out in the last year or two talking about with the amount of changes that all of these different states have put on the books already and voluntary commitments that utilities have made to basically get out of coal within the next 10 or 15 years. … Without a wholesale electricity market or an RTO, you’re looking at $3 [billion] or $4 billion extra per year in [costs] … for the privilege of failing on your collective greenhouse gas reduction goals — because you can’t get there.”
Interregional Planning Lacking
Panelists also lamented the lack of interregional transmission development since Order 1000 in 2011.
FERC Commissioner Allison Clements, who spoke to the conference June 21, said the commission plans to revisit the issue.
“I think interregional transfer capabilities is low-hanging fruit in terms of something that has widespread support; [it] certainly has support at the commission,” she said. “FERC has a role to play, because it’s just such a massive challenge. And the idea that it can get done in a ‘1,000 flowers blooming’ approach, as opposed to federally [mandated], seems hard.”
Clements said she hoped the commission’s April proposal will lead to more initiatives like MISO’s Multi-Value Projects. She also called for prudence in spending.
“If we are going to build out the type of transmission that every credible study tells us we’re going to need to do to serve customers reliably, we have to be careful about costs. If you want to build the big transmission to interconnect regions — which we need — get on board with grid-enhancing technologies; get on board with the ability of distributed energy resources to provide low-cost, flexibility to the system, because we need all of it. … Let’s ensure that [we are] taking advantage of the cheapest resources first.”
As part of the initiative, the National Renewable Energy and Pacific Northwest National labs will help DOE identify where transmission upgrades could relieve congestion resulting from electrification and increased renewable generation.
“The whole theory here is we have a case that is blessed by the regions; this is not something the labs go and do by themselves. … It really is working with everybody to find that those strong base cases and identify those areas,” Manary said.
She also discussed DOE’s transmission facilitation program, which allows it to borrow more than $2.5 billion to create a revolving fund to purchase capacity on new transmission to reduce developers’ risks. (See DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs.)
“The moment that DOE signs that capacity contract, we’re looking to resell it,” she said. “What I don’t know … is do we get keep that money [from transmission sales]? We are [in] active conversations with the Treasury.”
MISO expects the savings it delivers to members under a resource sharing pool to more than triple within 20 years, according to a new, forward-looking value proposition it debuted earlier this month.
The RTO said that by 2030, it will provide $4.3 billion to $5.8 billion in annual estimated benefits and $11.6 billion to $14.3 billion by 2040. The study estimates the current 11:1 benefit-to-cost ratio, based on $3.5 billion annual savings, will more than double to 26:1. (See “MISO Sees Members’ Savings Increase,” MISO Board Meets Amid RA Concerns, Emergency Alerts.)
During a Friday teleconference with stakeholders, MISO business analyst Savannah Miller said much of the benefits stem from a reduced need for additional assets because of capacity sharing and an optimized dispatch of renewable resources. She said the benefits will jump as decarbonization picks up.
MISO used a combination of its most conservative transmission planning future and the 2021 regional resource assessment, which considered its members’ decarbonization goals, for its long-term benefit analysis. (See MISO Resource Assessment: 140 GW Needed Within 20 Years.)
That data was compared against a scenario that assumed MISO had never been formed and utilities would have to meet their entire energy needs with their own generation or through bilateral contracts.
The grid operator concluded that its long-range transmission projects will “enable a more efficient utilization of the changing generation within MISO into the future.” The RTO assumes the $10.3 billion portfolio of 345-kV projects will come online by about 2030.
Miller said MISO expects to have a “completely different” resource mix by 2040. She said while staff know the energy transition will occur with or without it, the grid operator’s services will help members more easily access a reduced carbon fleet.
Mississippi Public Service Commission consultant Nick Puga said he wondered whether MISO’s base case was realistic enough. He suggested utilities would have banded together in some fashion to better share resources had MISO never been formed.
Staff said they simply used calculations with and without MISO calculations and didn’t think it was appropriate to hypothesize on what would have happened if MISO wasn’t formed.
MISO has issued a string of hot weather alerts, capacity advisories and conservative operations instructions since mid-June, mostly for MISO South.
Last week, both Alliant Energy and WEC Energy Group postponed plans to retire three coal-fired resources in Wisconsin by at least 18 months, citing tight supply in MISO Midwest. However, Consumers Energy’s new integrated resource plan approved will accelerate the retirement of its J.H. Campbell coal plant in western Michigan to 2025, 15 years earlier than originally planned.
The grid operator’s new market system, expected to be in service by late 2024, will house more nuanced types of wholesale market participation that better accommodate distributed and intermittent resources.
[EDITOR’S NOTE: A previous of this version of this story incorrectly reported that NPRR1110 had increased the black start servicer procurement period from two to four years. The procurement period was actually increased to only three years. (See “Board Clears NPRRs” below.]
AUSTIN, Texas — ERCOT’s Board of Directors last week took up two contentious issues between staff and stakeholders, resolving one and setting the other aside for the time being.
The board sided with ERCOT in approving staff’s proposed methodology for approving and denying planned generation maintenance outages, granting its appeal of a nodal protocol revision request (NPRR1108) that stakeholders passed in April. (See ERCOT Board of Directors Briefs: April 28, 2022.)
Staff said the rule change gives them much needed capacity and flexibility for planned outages while maintaining reliability. Stakeholders countered that the calculation limits outages when compared to history and that its assumed 10% growth rate for renewable resources is too low.
The Technical Advisory Committee “and staff are at loggerheads,” TAC Chair Clif Lange told the board. “We just wanted to raise these issues as areas we need to be looking at.”
The ERCOT methodology includes a maximum daily resource planned outage capacity (MDRPOC) calculation that sets the planned outages that should be allowed on each day of the next 60 months. Staff will review the methodology at least annually and work with stakeholders to make any necessary adjustments in allowing resources to schedule their maintenance outages. Any changes to the methodology will need board approval.
“We are providing a significant amount of outage availability,” interim CEO Brad Jones said. “We’re asking for some of [the outages] to be moved around. We’re trying to ensure not everyone takes these outages in October and late April.
Woody Rickerson, vice president of system planning and weatherization, told the board that the calculation’s installed inverter-based capacity is based on a 10th percentile score that allows room for growth.
“Ninety percent of the time, it’ll be higher in the future,” he said. “If we need more in the MDRPOC, we can change that. We’ve got some degrees of freedom that we can use in the future.”
Rickerson said staff conducted a backcast of the calculation against 2022 to determine whether they would have had to adjust the outage schedule. That would have happened three of four times, he said.
“That’s a pretty good number. We think we have this dialed in at the right amount,” Rickerson said.
The board again tabled NPRR1112, which would lower counterparties’ unsecured credit limit from $50 million to $30 million, over uncertainty of some of ERCOT’s numbers.
Jones said staff had “reason to believe” the numbers included some inaccuracies.
“We want to get them right and get them back to the board,” he said.
At issue is the amount of outstanding unsecured credit, currently $1.4 billion, that would be eliminated with the $30 million cap. Staff said dropping the cap would reduce the total to $400 million, but they could not definitively respond to Garland Power & Light’s Darrell Cline, speaking for TAC, when he said the reduction itself would be less than $400 million.
TAC will revisit the issue during its regular monthly meeting on Monday.
The directors agreed to again take up the measure during its August meeting. Should it pass the board then, it will become effective four months after Texas Public Utility Commission approval.
ERCOT last year proposed eliminating unsecured credit, but stakeholders countered with a revision request that would lower the limit to $30 million. After TAC approved the measure in April, ERCOT appealed the decision to the board, which tabled the measure later that month and requested information on other grid operators’ unsecured credit practices. (See “ERCOT’s Credit Limits Align with Others,” ERCOT Technical Advisory Committee Briefs: May 25, 2022.)
Staff found that all other ISOs and RTOs offer unsecured credit, limited to no more than $50 million per counterparty, and with no aggregate caps on the amount of outstanding credit. The grid operators’ total unsecured credit ranges from $100 million to $1.75 billion.
IMM: Out-of-market Actions Costly
Carrie Bivens, ERCOT’s Independent Market Monitor, clarified that the grid operator’s conservative operational posture this year has resulted in $216 million to $391 million in additional costs through its out-of-market actions.
Most of those costs come from the increased use of non-spin procurement and its effect on ancillary services prices in setting aside 6.5 GW in operating reserves each day. Increased reliability unit commitment (RUC) dispatch has only resulted in about $6 million in additional market costs, Bivens said.
The more frequent use of RUCs has added about $460 million year to date to the reliability deployment price adder. The adder is an indicator of the out-of-market actions’ impact on market outcomes and counters RUCs’ suppressive effects on energy prices, Bivens told RTO Insider.
She said the operating reserve demand curve (ORDC) has yielded about $900 million in market costs this year. The ORDC helps set prices in shortage or near-shortage conditions, the key to price formation in an energy-only market design, Bivens said.
The PUC last year lowered the ORDC’s clearing price from $9,000/MWh to $5,000/MWh and raised its minimum contingency level from 2,000 MW to 3,000 MW. The Monitor estimated shifting the curve has added about $476 million in energy costs by causing prices to rise more quickly at low shortage levels.
Bivens acknowledged to the Texas House of Representatives’ State Affairs Committee two days after the board meeting that most of those costs are passed on to consumers.
The PUC made the changes after market prices were stuck at the $9,000 cap for four days during the February 2021 winter storm.
In its annual State of the Market report released last month, the Monitor said ERCOT’s conservative operations approach runs counter to the energy-only market’s design. It said pricing outcomes have become “disconnected” from actual operational conditions in a market where high scarcity prices are designed to incent future investment in lieu of capacity revenues. (See IMM: ERCOT Conservative Operations ‘Not Compatible’ with Energy-Only Market.)
10 GW Thermals Could Retire with EPA Rule
Staff told the directors that its preliminary analysis of a federal rule limiting nitrogen oxide emissions assumed that over 10 GW of installed thermal generation would leave the market by 2026, requiring up to $1.5 billion to resolve local reliability issues.
The study assumed 10.8 GW of thermal generation, including 8.2 GW of aging coal-fired generation without scrubbers, would be retired. It added 20 GW of new generation, with only 4% representing thermal resources.
Rickerson said a steady-state transmission analysis showed the system would need $1.2 billion to $1.5 billion to “plug the holes left by the retirements.” He said an additional $2.7 billion to $5.2 billion could be needed to improve ERCOT’s regional transfer capability without the affected generation and that the probability of load shed in 2026 increases almost nine times when solar generation becomes unavailable.
Under EPA’s Cross-State Air Pollution Rule (CSAPR) federal implementation plan, NOx emissions budgets will be established for Texas and 25 other states, beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations.
Asked whether anyone would invest money in thermal plants that date back as far back as 1958, Rickerson said, “There’s a chance that could happen.” He said staff have been told that some plants simply don’t have the room for emissions-reduction equipment.
Public Utility Commission Chair Peter Lake said generation owners could face spending $200 million to keep 50-year-old plants in compliance. “So that’s pretty easy [as a decision],” he said.
The PUC, ERCOT and Texas’ environmental agency will all submit comments on EPA’s implementation plan, joining other grid operators and states in doing so. There were nearly 600 comments as of Friday afternoon.
Aguilar Resigns from Texas Central
Director Carlos Aguilar was a no-show for the board meeting, his first since resigning as CEO of Texas Central, the organization behind a proposed bullet train between Dallas and Houston.
Aguilar announced his resignation with a June 11 post on LinkedIn. He cited recent “news reports in the international press” for the announcement’s timing. Aguilar joined Texas Central as CEO in 2016.
The Federal Railroad Administration in 2020 approved plans for the 240-mile railroad. On Friday, the state’s Supreme Court ruled that Texas Central, which has affirmed its status as an operating company with the court, can use eminent domain to acquire land.
“Texas and the U.S. deserve the best transportation options, and I am convinced that in time, these will become a reality. We can do this,” Aguilar said in his post.
Board Clears NPRRs
The committee unanimously approved six NPRRs and a change to the planning guide (PGRR):
NPRR1100: clarifies that a generator or energy storage resource (ESR) may serve customer load when the customer and the resource are both disconnected from the system because of a transmission or distribution outage. The change is limited to configurations where the resource and customer load are using privately owned transmission and distribution infrastructure during a private microgrid island operation.
NPRR1110: modifies the black start service (BSS) confidential information, contract period and backup fuel requirements; increases the BSS procurement period from two to three years; and adds an on-site, 72-hour priority fuel requirement that can be waived in whole or in part to procure a sufficient number or preferred combination of resources.
NPRR1119: deletes extraneous language that should have been removed as part of NPRR978.
NPRR1121: automates the market notice used in the exceptional fuel cost submission process to notify market participants when the costs have been submitted for the operating day.
NPRR1129: allows ERCOT to post on its website a list of electric service identifiers for transmission-voltage customer opt-outs from the securitization of $2.1 billion for load-serving entities’ extraordinary costs incurred during the February 2021 winter storm.
NPRR1130: extends the sunset date for weatherization inspection fees from Sept. 1, 2022, to July 31, 2023.
PGRR100: revises the annual planning model base case update frequency from triannual to biannual, aligning it with the Steady State Working Group’s plan to adjust its current case-building schedule to a biannual basis.
ROCKPORT, Maine — FERC’s Notice of Proposed Rulemaking on transmission planning is narrowly focused on projects driven by public policy and emphasizes flexibility for states, Commissioner Mark Christie told the NEPOOL Participants Committee at its summer meeting in Maine last week.
Those factors made him enthusiastic about the proposal, which he called a “product of compromise” among members of the commission that has “creativity and flexibility absolutely written in.”
Released in April, the NOPR would direct transmission providers to revise their planning processes to identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“This particular, specific category … of public policy-driven projects are being driven largely by state policies. So state regulators should be at the forefront of deciding what should be the criteria for these projects, the benefits that get used in evaluation” and the cost allocation, Christie said. “I don’t know as much as you do about what goes on in Massachusetts, Maine or Vermont.”
That’s not to argue that FERC shouldn’t play a role in transmission planning, Christie said.
“We have a duty. I’m not saying that FERC doesn’t have a role. But I think when we get into something like planning for public policy projects … that we ought to defer and be respectful of what you all know more than we do.”
The proposal’s flexibility expands to cost allocation within RTOs, he said.
“That flexibility is there for large RTOs … to have cost allocation that can be granular enough to meet the needs not only of different RTOs, but different subsections within RTOs.”
Christie also emphasized that the proposed rulemaking is light on mandates, with only a long-term planning process required.
“Yes, there’s a lot of stuff listed in there,” he said. “But it’s not mandated. If the states say, ‘Thank you very much, FERC, but we don’t want to use these,’ the states can do that.”
Other PC Actions
In addition to hearing from ISO-NE and state leaders, the Participants Committee approved:
tariff revisions recommended by the Markets Committee to allow storage resources that inject energy into the grid but do not receive energy from it to register and operate as a continuous storage facility;
changes to tariff Schedules 22 (Standard Large Generator Interconnection Procedures), 23 (Standard Small Generator Interconnection Procedures) and 25 (Standard Elective Transmission Upgrade Interconnection Procedures) to identify that all new distribution-connected generation should proceed through the state interconnection process, as recommended by the Transmission Committee;
changes to Schedule 18 (Standard Large Generator Interconnection Procedures) and the incorporation of a new Attachment Q in response to FERC Order 881’s directive to incorporate the use of ambient-adjusted ratings for transmission lines, as recommended by the TC;
changes to Operating Procedure No. 22 (Disturbance Monitoring Requirements), including general updates, the listing of an additional facility in confidential Appendices A and B, and the addition of Appendix C (New England PMU Registration), as recommended by the Reliability Committee; and
changes to section 3.2 of tariff Attachment D to meet mandatory cybersecurity reporting requirements and section I.2.2 to modify confidentiality restrictions when the RTO is reporting cybersecurity incidents and events to certain federal agencies, as recommended by the MC.
CHARLOTTE, N.C. — Entities in the footprint of SERC Reliability can expect the 2022 summer season to bring continued challenges, attendees heard at Thursday’s open meeting of the organization’s Board of Directors.
Presenting SERC’s recently published 2022 Regional Summer Assessment, Melinda Montgomery, the regional entity’s senior director of engineering and advanced analytics, observed that elevated temperatures are expected across nearly all of the continental U.S. According to the National Oceanic and Atmospheric Administration’s (NOAA) projections issued in May, most of SERC’s footprint have a 40 to 50% chance of higher-than-normal temperatures in June through August.
“Back in May, I was really surprised to see the level of hot weather that we were already experiencing,” Montgomery said. “And it wasn’t just in isolated areas; it [was] over large sections of the Southeast, and actually across the country.”
Despite the elevated temperatures, SERC’s assessment shows that most of the region is likely to meet the season’s expected summer peak demands without resorting to emergency resources, non-firm energy imports and demand-side management. By comparison, NERC’s Summer Reliability Assessment, released last month, showed an elevated or high risk of energy emergencies across the Western Interconnection, Texas and much of the Midwest. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)
SERC’s 2022 Summer Resource Reliability Outlook shows most of the Southeast at low risk of resource shortfalls, except for the SERC MISO Central subregion, which may need to turn to emergency resources, non-firm energy imports, or demand side management to maintain reliability. | SERC
The one exception to this forecast is the MISO Central subregion, comprising parts of Illinois, Iowa, Missouri and Kentucky. SERC predicts that the subregion could lack sufficient resources to meet peak demand on its own under normal conditions and could have to rely on emergency measures in the case of higher-than-expected generation outages, high loads or other extreme scenarios.
While NERC’s assessment warned that ongoing droughts could lead to generation shortfalls in the Western Interconnection, Montgomery said this is not likely to be an issue in the Southeast; according to NOAA, the region has either a 50% or higher likelihood of greater-than-average precipitation this summer. The greater danger is from hurricanes: Colorado State University’s hurricane forecast, updated earlier this month, predicts the third above-average hurricane season in a row, with 20 named storms, all of which are expected to be hurricanes.
SERC CEO Jason Blake called the assessment “daunting” and said the RE is working to “really lean in and help make sure that we are … putting [utilities] in the best possible position.”
“You’re hearing already [that] we’re hitting peak demands in June,” Blake said. “So that’s something that is sobering, and something that we need to be very mindful of.”
Board members voted to approve SERC’s final business plan and budget for 2023. NERC will now submit the document, along with the business plans and budgets for the rest of the ERO Enterprise, to FERC for approval, which is expected by October.
SERC’s total expenses are expected to rise to $28.2 million next year, according to the final budget, slightly higher than the draft approved at the previous board meeting in March. (See “2023 Business Plan and Budget,” SERC Board of Directors/Members Briefs: March 30, 2022.) CFO George Krogstie explained that the difference was because the RE’s Finance and Audit Committee decided to expand the planned 3% increase to the market adjustment category — which governs spending on merit-based raises and promotions — by another 1.5%, in light of the high demand for cybersecurity personnel pushing up salaries for these positions.
The board approved this increase in advance at the March meeting as well. After SERC’s draft budget was approved by the board, it was submitted to NERC and posted for a 30-day stakeholder comment period. No comments were received, leading SERC’s FAC to accept the budget at its meeting on Wednesday with no changes.
New Members Accepted
As part of the consent agenda, the board agreed to accept four utilities as new members:
BayWa r.e. Operation Services: performs generator owner and generator operator functions for its sister company, Fern Solar, in North Carolina;
Capital Power: owns and operates the Cardinal Point wind facility in Illinois and the Decatur Energy Center in Alabama;
Silicon Ranch: owns solar farms across the U.S., including seven states in the SERC footprint; and
WestRock: owns and operates Green Power Solutions, a biomass power plant in Dublin, Ga.
All four new members will join SERC’s Merchant Electricity Generating Sector and participate in the RE’s Generator Working Group.
NYISO’s Business Issues Committee on Wednesday recommended that the Management Committee approve a pricing proposal for multiple active transmission constraints (MATCs).
Enhancements to the current transmission constraint pricing logic will enable NYISO’s market software to re-dispatch suppliers efficiently in the short term to alleviate constraints, as well as incentivize long-term investment in locations where suppliers could provide the greatest benefits, said Kanchan Upadhyay, energy market design specialist with the ISO.
MATCs can occur for two main reasons, either from topology or from the evaluation of contingencies on the same facility. MATCs arising because of topology, also referred to as “lines in series/lines in parallel,” show the same transmission line represented as multiple segments in the network topology (long radial lines) or parallel line segments. Transmission facilities that are constrained in multiple scenarios (base case and contingency case scenarios) being evaluated are referred to as “MATCs on the same facility.”
NYISO is proposing to develop functionality in the market software to identify redundant constraints across in-series and parallel transmission facilities, the most limiting of which would be binding and utilized for pricing purposes in application of the transmission demand curve mechanism (TDC). The remaining of such redundant transmission constraints would be non-binding and not utilized for pricing purposes in the application of the TDC.
The proposed solution seeks to provide better alignment between the use of physical resources versus the TDC in solving transmission constraints. It also aligns with the operational philosophy that relieving the worst/most limiting constraint across a transmission facility would generally alleviate other transmission constraints across the facility.
If prioritized for 2023, implementation would be contingent on approval by the NYISO Board of Directors and acceptance by FERC.
Critical Infrastructure Load
The BIC also approved a proposal to restrict participation of certain types of demand response in ISO-administered programs in order to protect critical electric system infrastructure load. The limitations were proposed to comply with NERC’s October 6, 2021, Standard Authorization Request to address extreme cold weather grid operations, preparedness and coordination.
Standard Recommendation No. 8 says, “Balancing Authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.”
The proposed tariff revision will address Standard Recommendation No. 8 as it relates to the NYISO demand response programs, said Francesco Biancardi, market design specialist for new resource integration.
The ISO is targeting July 2022 to file the applicable tariff language with FERC for implementation on Nov. 1, the first day of 2022-23 Winter Capability Period.
Bad Debt Loss Methodology
The BIC also recommended that the Management Committee approve a proposal from DC Energy to change the ‘look back’ period used in determining allocations to each participant to recover bad debt losses and payment defaults, expanding the period to three months.
Bruce Bleiweis, director of market affairs for DC Energy, presented the change and said the company believes the goal of the payment default and bad debt loss allocation methodology is to spread the loss fairly based on NYISO stakeholders’ overall billing determinants.
Market participants’ billing activity is not consistent within a month nor throughout the year, and this creates peaks and valleys for participants as a percent of total, whereas the new methodology “will smooth out the peaks and valleys” and represent an average obligation, he said.
The current methodology calculated each participant’s obligation “in the Billing Period in which the payment obligation that resulted in the loss occurred’ — DC Energy is bringing the same motion to MISO because they have a similar clause in their tariff, Bleiweis said.
One stakeholder asked whether NYISO supported the proposal or had any comment.
“We are indifferent to that timeframe,” said Sheri Prevratil, NYISO manager of corporate credit.
MISO Independent Market Monitor David Patton has been calling for a sloped demand curve in the RTO’s capacity market for what seems like forever.
The Potomac Economics president includes it as a recommendation in his annual State of the Market report for MISO every year; he even asked FERC to order the RTO to implement it in 2018. Nevertheless, MISO still has a vertical curve.
This year is a bit different, however. MISO is facing a 1.2-GW capacity shortfall in its Midwest region, and it is driven in part by inefficiently low prices “contributing to a sustained trend of retirements of resources that would have been economic to remain in operation,” according to this year’s report, presented by Patton to the MISO Board of Directors’ Markets Committee on Wednesday.
MISO’s current demand “curve” — a straight vertical line at the minimum capacity requirement — represents the fact that the RTO does not pay extra for surplus capacity, only increasing prices when there is a deficiency in a zone.
“The implication of a vertical demand curve is that the last megawatt of capacity needed to satisfy the minimum requirement has a value equal to the deficiency price, while the first megawatt of surplus has no value,” the report says. “Since prices will be set where the supply offers intersect with the demand curve, a vertical demand curve will almost always set the price close to zero when the market has even a small surplus of capacity.”
Or, as Patton told the committee, “When we impose a vertical demand curve, we’re basically saying, ‘We see no reliability value for any megawatts above the minimum requirement.’ That’s obviously not true.”
The clearing price for seven of MISO’s 10 capacity zones in the 2022/23 Planning Resource Auction (PRA) in April was the cost of new entry (CONE) of $236.66/MW-day, while the other three zones, in MISO South, cleared at $2.88. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) That marked a huge spike from the prices in the previous auction, which ranged from 1 cent in MISO South to $5 in the rest of the footprint. (See MISO Capacity Auction Values South Capacity at a Penny.) The jump signals an urgent need for additional capacity, especially in the northern zones.
With Patton’s sloped, or “reliability-based,” curve, prices are capped until the minimum requirement is fulfilled, and each subsequent megawatt is priced at a diminishing rate. Had it been used in the 2021/22 auction, prices would have ranged from $13 in MISO South to $150 in MISO Midwest. “Although this remains well below the cost of new entry of roughly $250/MW-day, this price would ensure existing resources that were needed to maintain reliability would remain in operation,” the report says.
MISO Response
Patton’s presentation on the curve received favorable responses from MISO officials and directors.
“I really think this is what we need to do,” CEO John Bear said. He argued, however, that generator retirements are not being driven by economics but by environmental policies. “So even if we fix this, we may have some troubles.”
Patton agreed that a different curve would not “magically solve the problem overnight.” But he countered that retirements purely for environmental reasons are rare.
“Sometimes there is an interplay because there can be an environmental requirement that comes out that requires a resource owner to spend money to comply … and that would be embedded in the going-forward costs,” he said. “That may be one of the reasons why the going-forward cost is as high as it is.
“But when a market doesn’t provide the revenues to cover those sorts of costs, then the unit retires, and it may look like an environmental retirement, but had we provided the revenue, some of these units would not have retired.”
Patton also said that “this isn’t entirely a MISO issue. I view this as also being a FERC issue. I don’t know how FERC looks at the actual prices there and finds them to be just and reasonable, because they don’t serve the basic purpose of why you have a capacity market in the first place.”
Director H.B. “Trip” Doggett, chair of the committee, noted that he has “asked MISO to attempt to arrange some training for us later this year … and one of [the] topics would be the sloped demand curve so that we can fully understand it.”
Short vs. Long Term
The report says that as long as the footprint does not experience above-normal heat this summer — a big “if” given the high temperatures already this month — MISO’s resources should be adequate. Though retiring units did not offer into the auction, they will still be operational for at least this summer, and the RTO is able to import power into practically any region of its footprint. And despite the shortfall in the auction, it saw a 200-MW net increase in capacity last year, with a 1-GW gas-fired plant coming online in MISO South and nearly 2 GW of wind resources across the footprint.
“In the long term, however, we are very concerned about MISO’s resource adequacy given the relatively low net revenues generated by MISO’s capacity market,” the report says.
