AUSTIN, Texas — Triple-digit temperatures continue to roast the state, where it is so hot that some roads are literally melting.
It’s so hot that Austin’s El Arroyo restaurant marked the city’s record-breaking 18th day above 100 degrees Fahrenheit on Thursday by using its famed sign, always good for a daily laugh, to vent about the ridiculous heat.
ERCOT’s meteorologist stopped just short of saying the state will see record heat this summer.
“I avoid saying ‘guarantee,’ but this is as close as you’ll get from a weatherman,” Chris Coleman told ERCOT’s Board of Directors on June 21.
Coleman said Texas’ weather is “running hotter” than it was at this same point in 2011, the state’s hottest and driest summer on record. With the state coming off its warmest April and second-warmest May on record, Texas should “approach” 2011’s extremes if summer continues with very limited rainfall, he said.
Unlike last summer, highs will frequently exceed 105 F, Coleman said. Austin has already broken 100 F more than 21 times this month, a record.
“It would be very bold to say we’re going to beat 2011, but everything now is falling into place,” he said. “We’ll at least challenge the record set in 2011.”
The high temperatures have resulted in record demand for ERCOT. The grid operator has set four new records this month for peak demand, the latest coming Thursday when it hit 76.6 GW. The old mark of 74.8 GW was set in August 2019; ERCOT has projected the system would reach of peak of 77.3 GW this summer.
ERCOT has about 91 GW of capacity available when every generator is running. It has been operating with a cushion of up to 6.5 GW of reserves to ensure there is enough power to meet demand as part of its conservative operations posture.
An Austin restaurant’s sign reveals how Texans feel about the summer weather. | El Arroyo
Peter Lake, chair of the Texas Public Utility Commission, said during a hearing before the Texas House of Representatives’ State Affairs Committee on Wednesday that ERCOT would have been “on the brink of rolling blackouts” six times in the last 12 months had it not built in the extra margin.
ERCOT has yet to issue an operation alert this summer, though interim CEO Brad Jones did ask Texans to manage their consumption last month in what was later termed a request. Several retail electric providers on Friday also sent emails to their customers asking them to conserve electricity during the afternoon.
“ERCOT is monitoring conditions closely and will deploy all available tools to manage the grid reliably,” the grid operator said in an email Thursday.
Since April, it has issued four operating condition notices, its lowest-level communication to the market in anticipation of possible emergency conditions. The latest was issued Thursday and expired Sunday.
The National Weather Service said a tropical low is expected to bring rain to the Gulf Coast and Central Texas this week, lowering temperatures to the low 90s and 80s and offering some hope the heat will relent.
“You’re going to need something to stop [the heat],” Coleman said. “Rainfall, either a series of fronts bringing 2 to 4 inches of rain multiple times, or a hurricane. But it’s pretty hard to get fronts past June.”
Indeed. According to the Climate Prediction Center’s initial outlook for July, it will once again be a hotter-than-normal month.
ARLINGTON, Va. — You’d be hard pressed to find a bigger booster of grid-enhancing technologies (GETs) than former SPP planner Jay Caspary, now vice president of consultancy Grid Strategies.
Speaking at the Infocast Transmission & Interconnection Summit last week, Caspary used the adjective “great” to describe topology optimization, storage as transmission and the ability to redeploy GETs at different spots on the grid.
“And that’s great … because congestion is going to move as we start building the grid,” he said. “So we can move this stuff around to where it’s most effective.”
Several other speakers — but not all — shared Caspary’s enthusiasm during the three-day conference.
Bhaskar Ray, vice president of development and interconnection engineering for Q CELLS USA, said planners should consider dynamic line ratings, which have proven valuable in operations. “I think we need to take a closer look in the planning mode to see if we can squeeze out another 10 to 15% of the transmission” capacity, he said.
Kenneth Jennings, general manager of renewable integration and operations for Duke Energy (NYSE:DUK), said he’s looking forward to the comments on storage as a transmission asset (SATA) in FERC’s June 16 Notice of Proposed Rulemaking on generator interconnection (RM22-14).
“I think it’ll be interesting to see what the comments are around transmission alternatives as far as the solutions to solve an overload,” he said. “I think that might open up an opportunity to look at storage differently perhaps than we do today. In general, we think about storage as requiring an interconnection request. It may make sense not to have an interconnection request for storage if it’s solving an overload.”
Caspary also sees an increasing role for SATA. “I think we need to consider that more and more to help create capacity on a system where we need it in the near term.”
He said he’s happy that FERC proposed requiring transmission planners to consider power flow controllers — phase-shifting transformers and phase angle regulators — that have been used on the grid for decades.
He also cited research that found replacing existing lines with advanced conductors could allow the addition of up to 30 GW of renewables to the system.
“We’re going to have to replace a lot of the existing wires on our transmission system over the next decade; I think we’ve estimated maybe 200,000 miles of lines [and] conductors that are going to reach their end of economic life in the next decade. That’s a lot of opportunity to increase capacity in existing corridors and leveraging existing structures,” he said. “Let’s be smart about this.”
But Bart Franey, director of transmission business development for National Grid (NYSE:NGG), was much less bullish than the other speakers, saying GETs will be limited to a “niche role.”
“DLR is not a substitute for rebuilding a line. When you have a 300% thermal overload on a light load day, you’re not going to put in DLR to fix that problem. I think, though, that it can work for minor overloads or as a stopgap solution. Power flow control devices [are] very, very handy, provided you have a parallel line where you can shunt the power over to it. … Advanced conductors … also have a specific application. It’s hard to put advanced conductors on a 100-year-old tower, because it can’t hold the tension. So I think there is a niche role.”
Franey shares the enthusiasm for storage as transmission, however. “I think there’s great opportunity that hasn’t really been tapped into,” he said. “I really think that there are just so many operational, reliability, transmission-type products that storage can offer in one setting and through some clever operations. I think that is going to be a key to an [non-wires alternative] type solution.”
FERC Commissioner Allison Clements said there is “more to come” from the commission on SATA. “Don’t take that as the commission plans to take action on that in the near term,” she cautioned. “I think there is a need to continue to think along those lines to see where the commission has landed in past decisions, and where we should go from there.”
States Want to Deploy More Storage, but Developers Call for Better Planning Tools, Valuation
WASHINGTON — Michigan’s new roadmap for energy storage has set ambitious targets for the state: 1,000 MW online by 2025, 2,500 MW by 2030 and 4,000 MW by 2040.
In Colorado, the state is targeting an 80% reduction in greenhouse gas emissions by 2030, which could trigger “investments of close to $12 billion in wind, solar, storage, peaking capacity and transmission,” according to Eric Blank, chair of the state’s Public Utilities Commission.
But for regulators like Blank and storage developers speaking at the American Clean Power Association (ACP)’s Energy Storage Policy Forum on Wednesday, meeting such targets presents a range of problems, from declining capacity values of projects pairing solar and storage to the challenges of financing storage in restructured markets.
“Solar just falls off more quickly than the peak demand,” said Blank, who appeared at the forum via a video hookup. “So, we’re finding reduced capacity value for both solar-plus-storage, and roughly every 5 to 10% increase in penetration reduces the capacity value by 20% … and we’re now seeing values at 70% coming down more towards 50%.”
Those figures raise a critical question, Blank said. “Is there a real limitation to how much [solar and storage] we can do?”
For Julian Boggs, manager for regulatory and policy affairs at Key Capture Energy, a New York-based storage developer, lower capacity values mean projects may not pencil out, especially in states with restructured markets.
Key Capture has been successful with projects in vertically integrated markets, Boggs said, because it has been able to “internalize a lot of the system optimization benefits in the [integrated resource plan] modeling, in looking out [at] your system over 20 years. … But it has been a huge challenge in restructured states. How do we finance given the capacity values and the energy values and whatever you can skim off energy and ancillary services markets?”
States may have aggressive climate goals and want to “deploy, deploy, deploy,” he said, “but how do you finance projects? How do you get long-term support? … We need to start thinking differently about how we use state support to fill in the missing money effectively in these restructured markets where the wholesale markets aren’t delivering the revenue piece.”
Similarly, Ted Wiley, president and chief operating officer of storage developer Form Energy, said utilities and regulators must also think differently about their long-term planning processes. With backing from Bill Gates’ Breakthrough Energy Ventures, Form is developing a long-duration technology that, Wiley said, could offer up to 100 hours of storage to provide resilience and reliability to the grid.
“There’s a whole host of other technologies that are being developed that are the next wave of storage. We need to be included in the planning process before we reach maturity in order to be a factor,” he said. “That planning has to happen now; [it] has to be a new kind of planning.”
Michigan Public Service Commissioner Katherine Peretick said that whatever the technology, valuation will be key to forward planning.
“If you have the right value for the technology that’s in front of you, you’ll pay for the services you want,” she said. Utilities need to “make sure that they are properly valuing the storage asset, both for the value it can provide to the grid, as well as how much it costs to operate.”
“Both sides of that coin are really necessary to make sure than when you plug that into the IRP model, it’s coming out with the right results,” she said. Developers will need to work closely with utilities to get the input numbers right, she said.
Not Ready for 100-hour Storage
While rising prices and supply chain and interconnection delays are expected to slow growth in the U.S. energy storage market this year, the sector scored a record first quarter, according to the most recent Energy Storage Market Monitor from ACP and industry analyst Wood Mackenzie. Total installations — including residential, nonresidential and grid-scale storage — totaled 955 MW/2,875 MWh, about a fourfold increase from Q1 2021, the report said.
That growth would have been even higher, but 1.2 GW of grid-scale projects that were originally scheduled to come online in the first quarter have been delayed, although about three-quarters are still slated to come online this year, the report said.
Grid-scale solar-plus-storage projects took a hit from the recent procurement bottleneck caused by the U.S. Commerce Department investigation of solar imports from Cambodia, Laos, Thailand and Vietnam. The impacts to project pipelines could continue into 2023, despite President Biden’s recent action to waive duties on solar imports from those countries for two years, the report said. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)
What the figures also show is that the market thus far is focused on shorter-duration uses of storage — an average of three hours — provided by lithium-ion batteries.
From a planning perspective, regulators and utilities are not ready for 100-hour storage, Colorado PUC Chair Blank said. In Colorado, “it’s literally outside our [electric load calculation] studies, which end at 16 hours.”
But, he said, Colorado does have a new program that will pay above-market rates for innovative technologies not yet at scale. But, he cautioned, in such cases, “the technology risks have to be on the vendor or the technology provider, and not on the customer or the utility. So, the form of the transaction shouldn’t be rate-based; it needs to be off-take.”
For Wiley, a new approach to planning should begin with asking, “What is the grid we are trying to build out? What kind of planning tools do we need for that?”
He also believes that the “levelized cost of electricity is no longer the metric we should be looking at. When evaluating storage, we should be looking at a value created at the portfolio level by an asset that allows and optimizes the portfolio, optimizes the generation, transmission and distribution [systems] across all of the asset classes.”
Clean Capacity
Key Capture’s Boggs said states may need to develop a “clean capacity” renewable energy credit to help them meet aggressive storage targets, like Michigan’s or Colorado’s.
Massachusetts’ clean peak standard — incentivizing technologies that can provide clean energy during times of peak demand — is “a halfway evolution … really still based on the REC framework,” he said. But the clean peak approach is still “incentivizing storage only to discharge during certain hours versus doing whatever is most valuable for the grid,” he said.
Blank sees RTO wholesale markets going to a “direct procurement-type approach” for energy storage. “These markets just fundamentally overpay for energy and underpay for capacity,” he said, so relying on a REC-type approach would be “a heavy lift.”
But both Boggs and Wiley argued that storage should be classified as a clean capacity resource.
“It’s certainly not a great idea from a policy perspective to be buying megawatt-hours from storage,” Boggs said. In using storage as capacity, “you’re buying the value of having a clean, flexible resource that is able to respond and optimize the system in any given number of circumstances and participate, whether it’s an ancillary services market; an energy market; whatever the market is [that] is most needed for you to participate in.”
The target for storage, said Wiley, “is to be replacing fossil-based assets that are providing capacity. So, in my mind, that leads me to a 24/7 type construct … a 24/7 carbon-free, clean capacity asset that can replace a fossil asset. That’s what we’re going for.”
Rhode Island Gov. Dan McKee’s proposed legislation authorizing a new offshore wind procurement passed the General Assembly on Thursday and is now on the governor’s desk for his signature.
McKee asked sponsors Sen. Dawn Euer (D) and Rep. Arthur Handy (D) in March to introduce the legislation (S2583/H7971), which the governor said at the time would further the “state’s position as the North American hub for industry activity.”
The House Corporations Committee on June 21 recommended that the House pass the bill with amendments that include increasing the original proposed 600-MW procurement to between 600 and 1,000 MW and directing Rhode Island Energy (RIE) to issue a request for proposals by Oct. 15.
“The offshore wind industry is driving investment in job growth in the local green economy, and this is a good bill that moves us in that direction,” Rep. Joseph Solomon (D), chair of the Corporations Committee, said on the House floor.
RIE would evaluate developer bids on environmental and fisheries impacts, economic benefits, and diversity, equity and inclusion measures. Each RFP would need to include a plan for enabling “historically marginalized communities” to access employment and vendor opportunities related to the project.
The bill would also give the Public Utilities Commission the authority to rule on disputed contract terms, if any occur during negotiations, and direct RIE to secure a final contract.
New procurements under this legislation, together with the already-commissioned 30-MW Block Island Wind Farm and the planned 400-MW Revolution Wind project, could provide 50% of the state’s estimated energy needs, according to a statement from the House.
The legislature also sent a bill to the governor on June 21 that would amend the state’s Renewable Energy Standard to require 100% of electricity to come from renewable sources by 2033.
ARLINGTON, Va. — When comments are filed in August on FERC’s transmission planning and cost allocation rulemaking, one issue sure to generate controversy is the commission’s proposal to abandon Order 1000’s competition measures.
Comments on FERC’s April Notice of Proposed Rulemaking (RM21-17), which would allow incumbent transmission owners a federal right of first refusal (ROFR), are due Aug. 17, with reply comment due Sept. 19. The NOPR would allow incumbents to exercise the ROFR on regional projects on the condition that they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project. (See ANALYSIS: FERC Giving up on Transmission Competition?)
Last week the Electricity Transmission Competition Coalition, a group of industrial consumers and others, asked the chairman and ranking members of the U.S. Senate Finance Committee to oppose FERC’s proposal, saying transmission competition was essential to respond to electricity price inflation. The issue also was the subject of debate last week at Infocast’s Transmission & Interconnection Summit.
FERC said it was changing course because it feared that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission. Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, the commission said. Regional transmission facilities subject to competitive procurements represent only a small portion of transmission investment in recent years, it said.
Commissioner Allison Clements defended the change in remarks at the transmission summit June 21.
“When you look at the record and the lived experiences under Order 1000, you see that the attempt at opening up regional transmission developments to competition had mixed results at best,” she said. “And so we were trying to find a way to mimic the impact of competition to some extent to get cost savings for customers outside of the approach that was taken in Order 1000 and faced a lot of barriers.”
She said the specifics of the new approach will be spelled out based on comments in the docket and at a technical conference Oct. 6 (AD22-8). “We are thinking about big concepts like independent transmission monitors and what role they might play relative to help managing costs,” she said.
Erik Heinle, D.C. Office of the People’s Counsel | Jay Caspary
During a panel discussion later, Erik Heinle, senior assistant people’s counsel for federal affairs and wholesale markets for D.C., called the ROFR proposal “an unfortunate … step backwards.”
“I think we all can agree that that competitive wholesale markets have really brought enormous benefit, both to suppliers and to load. And I think it’s unfortunate, from our perspective, that we don’t use those same tools in transmission planning and bring the same benefits of competition to transmission planning, because we can see not only lower costs, but potentially better solutions to address transmission issues.
“We certainly understand that Order 1000 hasn’t worked as well as the commission hoped,” he added. “But that doesn’t necessarily mean we give up on the goals of Order 1000. Instead, [we should] find ways to double down and improve those goals.”
But Brian C. Drumm, representing Fortis’ ITC Holdings (TSX:FTS), which owns 16,000 circuit miles of transmission in the Midwest, called Order 1000 “a failed experiment,” saying competition has delayed transmission projects without bringing savings to ratepayers.
“The MISO [Multi-Value Project] portfolio in 2011 was the last substantial regional build out in MISO. And I think that’s a direct result of this Order 1000 imposition of competition and competitive bidding,” said Drumm, ITC’s director of regional policy and RTO engagement.
Brian C. Drumm, ITC Holdings | Jay Caspary
Drumm said projects in MISO’s proposed $10.3 billion long-range transmission plan that will be subject to competitive bidding will take two years longer to complete than projects that are exempt. In May, the RTO asked FERC’s permission to change its process to exclude “short segments and conductor-only” work from competitive bidding eligibility (ER22-1955). (See “Competitive Bidding Question Remains Open,” MISO Makes Business Case on Long-range Tx Plan.)
“To the extent you can start building on a large scale and regional basis, you’re going to capture economies of scale that RTOs, in particular, are really well suited to deliver,” Drumm said. “But for those [projects that are competitively bid], there’s a two-year delay for them to get into service; that delay results in increased costs to ultimate consumers. … It potentially could impact the operation of the portfolio as well.”
Drumm declined to say if transmission providers deserved blame for obstructing competition.
“FERC was trying to get more productivity and efficiency, lower costs into the transmission planning of transmission projects. And ultimately, what we’ve seen is … a lack of collaboration amongst highly regulated utility entities and transmission providers that previously worked well together,” he said. “I’m not really sure of all the reasons, but I do know what the results were: This resulted in delay and increased costs. So [the blame is] kind of irrelevant.”
MIT economist Paul Joskow issued a working paper in 2019 that concluded “the experience to date is sufficiently promising to consider expanding the use of open competitive procurement solicitations for transmission projects.”
The Brattle Group issued a report the same year for independent developer LS Power that concluded that competitive solicitations saved an estimated 20 to 30% of project costs compared to traditionally developed projects. LS Power won PJM’s first Order 1000 competitive project, for upgrades to Artificial Island in New Jersey, after promising a cost cap.
“Thirty percent savings … it’s hard to say that’s a failed experiment,” said Jennifer Chen, senior manager of clean energy for the World Resources Institute. “Maybe there are places where we can compromise … but I would say we should do our very best to make this process as competitive and transparent as possible, and make sure that we are investing money wisely.”
Drumm’s comments also drew a rebuttal from Ali Amirali, senior vice president of Starwood Energy Group Global. “For those who don’t believe that [competition] was working, come talk with me and LS Power, and we’d be more than happy to show you where it is working.”
[EDITOR’S NOTE: A previous version of this story incorrectly stated that initial comments on the NOPR are due by July 18. Comments were initially due by that date when the NOPR was first approved, but on May 25, FERC granted a request for additional time, setting a new due date of Aug. 17.]
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.
Chris Coleman, ERCOT | © RTO Insider LLC
