While utility commissioners are concerned about variable energy generation when it comes to resource adequacy, it’s extreme weather that’s really keeping them up at night, speakers said during a webinar hosted by WECC.
During the March 2 webinar, part of WECC’s monthly resource adequacy discussion series, panelists explored myths and realities of resource adequacy. The first potential myth discussed was whether the rising volume of variable generation is playing a major part in resource adequacy concerns.
California’s duck curve, in which solar energy drops off at the same time electricity demand is peaking in the evening, was cited as an example of variable generation.
For panelist Eric Blank, chair of the Colorado Public Utilities Commission, the problem of variable generation is increasingly “understood, quantifiable and capable of solution.”
But extreme weather events, ranging from heat waves to winter storms, haven’t been consistent with past weather patterns and are a “new world,” he said.
“I think it’s less a variable generation problem and much more an extreme weather and correlated outage problem,” Blank said. “That’s what keeps me up at night.”
Panelist Mary Throne, a commissioner on Wyoming’s Public Service Commission, said variable generation does play a role in RA. Combined with extreme weather, she said, the two issues keep her up at night.
Another issue is to what extent extreme weather events, previously considered to occur with low probability, should be factored into resource planning.
Branden Sudduth, vice president of reliability planning and performance analysis at WECC, explained that in the past, planning revolved around determining the hour of peak demand in a given year. The thinking was that if demand in that peak hour could be met, resources would be adequate the rest of the year.
Now, Sudduth said, planners are starting to change their approach.
“People are recognizing the need for more of the stochastic planning,” Sudduth said. “Looking at a wide range of generator availability conditions and then coupling that with a wide range of demand conditions as well. And then using those stochastic models to help us identify specific hours of the year when demand might be at risk.”
But cost is also a consideration when planning for extreme conditions.
“We have to ask the questions, … see what happens in extreme conditions and correlated unit outages,” Blank said. “But the question, ‘Do we incur the cost to manage to those scenarios?’ is a much more difficult question [without] obvious answers.”
Electrification is another piece in the puzzle.
“You have to consider it in terms of changing weather patterns and increasing demand as we attempt to move toward more electrification,” Throne said, although she noted that electrification of vehicles and buildings was likely to occur slowly in Wyoming.
Another potential misconception panelists discussed was whether an organized market, such as a Western RTO, will be the solution to resource adequacy issues.
Throne said the impact of an organized market is still unknown.
“We are going to move incrementally, and whether we ever get to a full RTO remains to be seen,” Throne said.
Blank said an organized market isn’t going to solve every problem, but it has the potential to accelerate transmission expansion and lead to better regional planning.
“If it’s done right, it could produce a lot of benefits,” he said. “And if we screw it up, it could create a mess.”
Lansing, Mich. — After a month’s worth of weather-related outages that affected as many as 1 million customers across Michigan, the state’s two largest utilities are facing inquiries into why so many of their customers were left in the dark and why it took so long to restore power.
The Michigan House Energy, Communications and Technology Committee will hold a hearing March 15 looking into massive outages that primarily struck utility customers of Consumers Energy (NYSE:CMS) and DTE Energy (NYSE:DTE) over two consecutive weeks in February and the first days of March.
The Senate Energy and Environment Committee also is planning a hearing on the outages, but a list of witnesses has not been completed nor has a date been set, according to an aide to Chair Sean McCann (D).
In addition, the Public Service Commission soon will issue a request for proposals from third-party outlets to audit CMS and DTE regarding their ability to handle storms and respond to outages. The audits, ordered in October, could take a year to complete.
While customers of other utility systems — including the Lansing area’s municipal utility — also lost power during the series of storms, most of the affected residents were customers of Michigan’s two largest utilities, CMS and DTE.
As many as 1 million customers were left without power after a major ice storm hit the state on Feb. 22. Another ice storm hit on Feb. 27, knocking out power to some who had earlier lost service and had it restored; it also affected a new batch of customers. A week later, a major snow and windstorm knocked out power to another 200,000 customers, most of those DTE customers in the Detroit area.
Social media accounts across the state were filled for several weeks with outrage over the delays in having service restored. Many customers went more than a week without power, a situation that drew national attention. Affected customers complained that they pay some of the highest utility rates in the Midwest while enduring some of the worst service in the nation.
DTE Energy called on more than 3,500 field workers to restore power from damage caused by a storm that had 15 cities in Southeast Michigan declare snow emergencies in early March. | DTE Energy
Michigan ranked 46th among the states and the District of Columbia in reliability, according to a 2022 report by the Citizens Utility Board of Illinois that compared the average duration and frequency of outages along with average time to restore power.
The winter outages especially infuriated DTE customers who for several years have suffered blackouts following major wind and rainstorms during the summer.
In Ann Arbor, which along with the rest of Washtenaw County was hard-hit by outages, a city council member introduced a resolution calling on the legislature to help local communities be better prepared and more resilient against outages. The resolution, introduced by Ayesha Ghazi Edwin, urged the legislature to approve bills creating community solar systems as well as letting communities invest more in renewable energy and electric storage systems. The council has not yet acted on the proposed resolution.
Rep. Helena Scott (D) told the Detroit News that the House hearing will look into what needs to be done to prevent future outages.
“We cannot and will not simply accept that this is our new normal,” Scott said. “The power grid and associated infrastructure must be reinforced, updated and improved so that residents are safe, warm and receive the services they pay for.”
PSC Chair Dan Scripps will be one of the witnesses expected before the House committee hearing. The committee has not yet released a list of witnesses, but a spokesperson for CMS said the company’s senior vice president of engineering and vice president for electric operations will be speaking.
PSC spokesman Matt Helms said the audits are needed because “over the last couple of years, the commission has been aware that Michigan’s electric utilities are facing significant new reliability challenges as the state sees increasingly severe and frequent storms.”
Helms said the audits were the first time the PSC had undertaken such a comprehensive review of the utilities’ systems.
CMS spokeswoman Katie Carey said the utility is spending $5.4 billion over five years to strengthen its grid and reduced customer outages by 20% last year. “We understand the frustration that people are feeling after the historic ice storm, and this strengthens our resolve to do better,” she said. “We are open to ideas from the Michigan Public Service Commission, policymakers and others.”
DTE spokesman Peter Ternes said the company has spent more than $5 billion rebuilding its grid over the last five years and plans to increase its spending to $9 billion over the next five years. “DTE looks forward to appearing before the House and Senate energy committees to discuss our shared goals of improving reliability, delivering cleaner energy and maintaining affordability for our customers,” he said. “Our customers deserve a reliable electric grid, powered by cleaner energy.”
Supply chain issues, the trend toward electrification and cyber and physical security all weigh on the minds of the nation’s electric cooperatives, CEOs of several co-ops said in a media call Tuesday.
The CEOs were gathered in Nashville, Tennessee, for the annual meeting of the National Rural Electric Cooperative Association (NRECA), whose members say they supply energy to 42 million consumer-members across 48 states. NRECA CEO Jim Matheson said that the co-ops’ member ownership model gives them “a particularly consumer-centric view on how we do our jobs” and a unique incentive to ensure reliable service.
Attendees acknowledged that many reliability challenges are common across all types of utilities, but said the issues are often more acute for co-ops, which can have limited resources compared to larger investor-owned utilities. The growing wait time to obtain spare parts is one such area. Pointing to the spread of electric vehicles and the increased use of electricity for heating and cooking, Electric Cooperatives of Arkansas CEO Buddy Hasten warned that shortages could cripple operations just as the grid is needed most.
“We’ve always been responsible — all utilities, not just co-ops — about keeping spare inventory. But we’re chewing through that spare inventory, and we can’t restock it fast enough,” Hasten said. “I think there [are] starting to be some real chinks in the reliability wall, where [if] the right storm, the right set of conditions comes in, all of a sudden, you may go to the cupboard, and it’s bare.”
Matheson added that the rising consumer demand, paired with the ongoing replacement of conventional generation sources with renewable energy, has also made it essential to install new electric infrastructure as quickly as possible to deliver the intermittent power rapidly to where it is needed. Yet that the permitting process for new construction still does not move as quickly as utilities need, he said.
“I think the electrification push in this country, and retirement of existing assets, shines a much brighter light on the challenges of the permitting delays we face as a sector,” Matheson said. “For decades, people thought that we need streamlined permitting, we need permitting that works better. This time we really do. We need a predictable process — not that we want to skirt any rules, but something that’s predictable and that’s reasonable.”
The conversation also touched on preparations for cyber and physical security in light of recent high-profile incidents involving electric infrastructure, such as the Moore County, North Carolina, substation attacks in December that left 45,000 customers without power for days. (See Duke Completes Power Restoration After NC Substation Attack.) Matheson acknowledged that hardening infrastructure can be daunting because “there’s not a one size fits all.”
The Duke Energy substations in Carthage (left) and West End, N.C., that unidentified attackers shot on Dec. 3, 2022, leading to the loss of power for around 45,000 customers in Moore County. | FBI
“Every location is different, and for physical security, a substation in location A, compared to B, compared to C, there may be different mitigation efforts you could deploy to create greater physical security at that particular location,” Matheson said. “So, the advice that we’ve heard — and this is the investor-owned [utilities], the [municipals], the co-ops … is you really have to do a thoughtful, asset-by-asset inventory of your system, and determine in each case what the relative risk is and what the potential opportunities are to mitigate risk at that physical location.”
Chris Jones, CEO of Middle Tennessee Electric, said that while his organization has made substantial investments in cybersecurity, there’s no way to know if it was enough. He said that one of the benefits of trade organizations like NRECA is the opportunity to collaborate and share approaches to common problems.
“There’s no end to the amount of money you could spend, [so] we’ve got to weigh this out — what’s the risk, versus how much can we reasonably invest to mitigate those risks?” Jones said. “I think one of the great benefits of the electric cooperative network is our ability to share information and ideas with each other. … These are very difficult and challenging questions, but I take comfort in the fact that I have peers across the country that I can share notes with, and we’re going to do our best to figure it out.”
The U.S. Department of Energy on Wednesday announced $6.3 billion in funding to decarbonize energy intensive industries such as aluminum, steel and cement plants, with the White House calling the new grant program the “largest investment in industrial decarbonization in American history.”
The funding is intended to “accelerate decarbonization projects and provide American industry a once-in-a-generation ‘first mover’ advantage in the emerging global clean energy economy,” a White House fact sheet published Wednesday said.
“Widespread demonstration and deployment of decarbonization projects within these industries is key to achieving [President Biden’s] goal of a net-zero carbon economy by 2050 and will help strengthen and secure America’s global leadership in manufacturing for decades to come,” it said.
The new Industrial Demonstrations Program, funded by the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, will “focus on the highest emitting industries where decarbonization technologies will have the greatest impact,” DOE said in a news release.
Other industries that will be eligible for awards include chemicals and refining, food and beverage, and forest products and paper, the agency’s Office of Clean Energy Demonstrations, which will administer the grants, said on its program page. In addition to industry, grant recipients can include technology developers, universities and state and local governments, among others, OCED said.
In its funding notice, the office said it expects to make up to 55 awards of $35 million to $500 million each, with a minimum 50% cost-sharing by awardees. Priority will be given to projects that “offer deep decarbonization, timeliness, market viability and community benefits,” it said.
“Industrial emissions account for roughly one third of the nation’s carbon footprint, and the industrial sector is considered one of the most difficult to decarbonize due to the diversity of energy inputs, processes, and operations,” OCED said. “The sector’s emissions result not just from fuel for heat and power, but also from feedstocks and processes that are inherently carbon intensive.”
The latest effort is part of the Biden administration’s push to reduce emissions from “across the industrial sector, including by demonstrating decarbonization projects at scale in this decade — solutions that had previously seemed decades away,” DOE said in a news release.
“Widespread demonstration and deployment of decarbonization projects within these industries is key to achieving the President’s goal of a net-zero economy by 2050 and will help strengthen and secure America’s global leadership in manufacturing for decades to come,” it said.
Buy Clean
The Biden Administration is also trying to build a larger market for low-emissions products. It published updates Wednesday to its Buy Clean Policy, including the start of a new federal-state partnership.
The administration launched the Federal Buy Clean Initiative last year to “leverage the $630 billion of annual purchasing power” by the federal government — the “largest direct purchaser in the world and a major infrastructure funder” — to increase the use of American-made, low-carbon materials in federal construction projects, it said.
Twelve states have joined that effort, it said.
“Today, the Biden-Harris Administration is launching the Federal-State Buy Clean Partnership with commitments from … leading states,” including California, Illinois, Michigan, New Jersey, New York, Oregon and Washington, it said. “These states have committed to prioritize efforts that support the procurement of lower-carbon infrastructure materials in state-funded projects, and to collaborate with the federal government and one another to send a harmonized demand signal to the marketplace.”
The Natural Resources Defense Council praised the administration’s moves in a news release Wednesday.
“With this $6 billion funding stream and other federal incentives like Buy Clean, American manufacturers have the opportunity to produce the world’s most competitive low and zero-carbon industrial materials,” Sasha Stashwick, NRDC’s director of industrial policy, said in the release. “These are the products buyers around the world will be seeking in the clean economy.”
Washington’s first cap-and-trade auction pulled in nearly $300 million in revenue, according to a summary report issued by the state’s Department of Ecology Tuesday.
All 6,185,222 allowances offered in the Feb. 28 auction were sold, clearing at a settlement price of $48.50. That was well above the floor price of $22.20 and “in the range” of an independent analysis commissioned last summer, the agency said in a statement after results were released. Each allowance entitles a holder to emit one ton of greenhouse gases.
The auction summary showed that 56 companies, utilities and public institutions bid into the auction, but it did not indicate which bidders were successful.
The Ecology Department is required to provide a final revenue report by March 28.
“This is truly historic for Washington and for the global movement toward a low-carbon future,” Gov. Jay Inslee said in the statement. “This cap-and-invest system is crucial to our approach to addressing climate change, and we are very encouraged to see this program starting off so well.”
“With the cap-and-invest program now fully underway, we can begin providing critical support for reducing emissions in our state and helping communities deal with and prepare for the effects of climate change,” said Ecology Director Laura Watson.
Washington’s Democrat-controlled legislature in 2021 passed the law establishing the nation’s second cap-and-trade program — behind California — along party lines. Last year state agencies hammered out regulations to put that law into effect.
The Feb. 28 auction was the first of four quarterly auctions to be held this year by the Ecology Department.
In January, Washington officials told the state Senate Transportation Committee that the cap-and-trade auctions could raise almost $1.5 billion through fiscal 2024 and reiterated their view that a new low-carbon fuel standard will raise gas taxes by about one penny per gallon. (See Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024.)
Later this legislative session, the state Senate and House plan to allocate revenue from the first cap-and-trade auction. The Ecology Department estimates $484 million in cap-and-trade revenue will be raised in fiscal year 2023 (July 1, 2023 to June 30, 2024) and $957 million in FY 2024.
The revenue from the auctions is expected to shrink over time as the number of emission allowances is reduced. Estimates are considered less reliable as they are projected farther into the future. The agency currently estimates $901 million in revenue for FY 2025, $730 million in FY 2026 and $592 million in FY 2027.
MISO said it experienced a “complete loss of monitoring or control capability” at its control center last week, setting off short-lived energy imbalances.
According to the grid operator, the March 1 incident lasted about 41 minutes. It said it was administering routine quarterly maintenance on its energy management system (EMS) at midnight to update modeling. However, “issues with the update” sent incorrect dispatch signals to generation through the RTO’s automatic generation control tool.
MISO said the glitch led to an imbalance in its balancing authority and a Balancing Authority ACE Limit (BAAL) event. It said its area control error (ACE) reached as high as 2,000 MW, resulting in a 17-minute BAAL event.
The ACE then swung as low as -4,285 MW, resulting in a second BAAL event for 11 minutes, MISO said. It said it used “backup tools and processes” to regain the control room’s monitoring and control capability.
The grid operator said it reported the disturbance to the Department of Energy through the agency’s electric emergency incident and disturbance report (form DOE-417), which is used to collect information on incidents and emergencies.
MISO said its backup plan included reverting temporarily to its earlier December model. It said the model worked as intended.
“We were able to address the incident in less than 15 minutes and move to our new model within a couple of hours, spokesperson Brandon Morris said in an emailed statement to RTO Insider. “We are reviewing the situation and will improve the processes under our new model manager and EMS systems.”
MISO is working to deploy a new EMS and a one-stop model manager that will serve as a single record for maintaining members’ modeling information. The RTO said it experiences redundant data entry and review because it lacks a unified modeling process for reliability, markets and planning. (See MISO Pivots to Models, Market Engines in New Platform Replacement.)
FERC has been working through compliance filings on Order 2222, but none of the ISOs or RTOs have yet to have aggregations of distributed energy resources actually participate in their markets.
The commission defines DERs as any resource located on the distribution system or behind a customer meter, or any subsystem thereof, said David Kathan, a former FERC staffer who worked on the issue and now runs his own consulting firm. Speaking on a webinar hosted Wednesday by the United States Energy Association, Kathan listed rooftop solar, community solar, electric vehicles, cogeneration facilities, distributed storage, demand response and others as potential DERs.
Load management and solar were the dominant DERs from 2015 to 2020, and they are expected to continue growing at a healthy clip but will be joined by additional resources ramping up deployments this decade such as EVs and storage, Kathan said.
Hawaii is ahead of most states on renewable deployments with a goal of getting to 100% renewables by 2045, and DERs will play a key role there, he said.
“I know Hawaii is not exactly, you know, the normal state in the United States; it’s islands,” Kathan said. “It has a different set of resources and challenges. And they like to call themselves a postcard for the future.”
Across the entire state, DERs could make up 15% of electricity by 2045, but they could be as high as 23% on the island of Maui. It is important for grid operators to have visibility into those resources, but that requires changes to how they have operated in the past.
“Many DERs, especially behind-the-meter resources, are too small to participate in wholesale markets,” Kathan said. “Most RTOs and ISOs have set a minimum offer size requirement of at least 100 kW.”
Individual DERs often do not have the capability, nor the interest, to participate in the markets, but they are happy to have aggregators do much of the work so they can get paid, he added.
“At present, no DER aggregations participate in wholesale markets … and will mostly have to wait until implementation of 2222 by the RTOs and ISOs,” Kathan said. “Most plan for effective dates for their participation between 2024 and 2026.”
MISO has proposed an implementation date of 2030, but that is still pending FERC approval. CAISO enacted its DER aggregation rules back in 2016, and many of the elements it set up then informed Order 2222. But even there, no DERs have participated in the wholesale markets yet.
“It is not necessarily a problem with the rules, and more having to do with issues that are still not resolved at the state level,” said Kathan. “And in particular, whether various resources, like DERs and demand response, are able to see resource adequacy credits has been a major issue on why there has not been as much participation.”
Getting the rollout of DERs and how they work on the grid right is going to be important when it comes to decarbonization efforts, said Omar José Guerra Fernández, of the National Renewable Energy Laboratory.
Much of the discussion has been on how to decarbonize the power sector, “but then we also need to decarbonize the industrial transportation and building sectors,” said Guerra Fernández. “And, in my opinion, this is the place where the DER group will play a significant role.”
DERs will help ensure that cars are charged up when the grid is producing clean power, providing a key cross-sectoral role in decarbonization, he added. It will also help decarbonize the building sector in ways that central station renewables are not capable of by adding distributed generation, heat pumps and other technologies that can ensure buildings do not produce greenhouse gases.
“DERs are a variety of technology that will allow us to do this cross-sectoral integration of the energy systems to help achieve net zero by 2050, or maybe before,” Guerra Fernández said.
North Carolina lawmakers on Tuesday peppered state utility regulators with questions about widespread outages stemming from a winter storm over the December holidays.
Duke Energy had to resort to rotating outages for the first time in its history on Dec. 24 to avoid even worse impacts as Winter Storm Elliott brought historic cold weather and extremely high demand, impacting about 500,000 — or 15% — of the utility’s customers.
The North Carolina Utilities Commission has been looking into the outages, but its investigation is still ongoing, Chair Charlotte Mitchell said during a hearing the state House of Representatives’ Energy and Public Utilities Committee.
The cold weather had been expected and utilities were planning to meet associated demand, but “the temperature dropped more rapidly than the weather forecasts were anticipating,” causing “problems for the utilities,” Mitchell said.
The rapid drop in temperature meant that the utilities’ load forecasts were off by 10% and that unexpected demand contributed to the outages.
“There had been no history of a temperature drop like the one that was experienced during that period of time,” Mitchell said. “So, the model was off, and to the extent that the model is the predicate for … the planning of generation resources to meet load there, there was sort of a problem.”
On top of that, the extreme cold impacted generation. Despite the NCUC’s focus on winterization for more than a decade, some units were knocked offline during the extreme cold.
Rep. Larry Strickland (R) asked whether regional markets, such as PJM, performed any better during the cold snap over the holidays.
“It’s tough to say whether it fared better,” NCUC Public Staff Executive Director Christopher Ayers said. “I can tell you PJM came very, very close to rolling blackouts. But they, to my understanding, did not experience rolling blackouts.”
Dominion Energy’s territory in northeastern North Carolina requires Ayers, the state’s consumer advocate, to follow PJM; he noted the RTO lost up to 23% of its generation and is in the process of “fining” generators who did not perform under its capacity performance mechanism.
“Is it possible that integrating the grid more closely with surrounding states could help prevent blackouts in North Carolina?” Strickland asked. “Shouldn’t we study this further to find out?”
Generally, the more integrated a state is in regional markets, the more resources it can call on and access it has to a greater diversity of supply, Ayers said.
“If they don’t have power to send you, then there’s no power to be received,” he added. “So, you know, there’s no easy answer to that, at least from what we have seen in the data that we have looked at.”
PJM was unable to bail out Duke’s utilities in the Carolinas during the cold snap because it was facing the same weather and also ran into supply issues, though it avoided rolling blackouts, Mitchell said.
The cold weather led to inaccuracies in the demand forecasts of other grid operators, including PJM, and while that experience will now be included the historical data feeding future forecasts, Mitchell said factoring in extreme weather is an important issue going forward.
“We are concerned about the divergence and the strain that it causes the system operators when all of this load shows up that they were not anticipating,” Mitchell said. “So, it’s an issue that we — sort of the greater universe of electric utilities, natural gas utilities and regulators — have to study.”
A net zero bill unveiled by New Mexico lawmakers last week has stumbled, failing to advance out of a Senate committee on Tuesday.
Senate Bill 520, sponsored by Sen. Mimi Stewart (D), calls for the state’s direct greenhouse gas emissions to be reduced to 90% below 2005 levels by 2050. Interim GHG reduction targets in the bill are 50% by 2030 and 75% by 2040.
An earlier version of the bill included a requirement to offset remaining GHG emissions in 2050 and beyond. The bill’s authors decided to leave offsets, and a system for managing them, as a topic for future legislation.
But SB 520 may now be dead after the Senate Conservation Committee failed to advance it. A motion to pass the bill failed on a 4-4 vote. One committee member was absent.
The committee potentially could revive the bill by bringing it back for another vote. New Mexico’s 60-day legislative session ends at noon on March 18.
The committee’s three Republican members voted against the bill and were joined by Sen. Joseph Cervantes (D).
Cervantes criticized the bill for its lack of consequences for not meeting the GHG reduction targets.
“There’s no accountability in here at all,” he said.
“If we really want to do things, let’s do things,” Cervantes said. “Let’s give meaningful standards, and let’s give consequences, and let’s give clear direction.”
Stewart, the bill sponsor, said that even though the bill didn’t have “huge accountability,” it was an important step. SB 520 would codify GHG reduction targets outlined in a 2019 executive order from Gov. Michelle Lujan Grisham. The bill “sets an essential framework for our continued climate action,” Stewart said.
“It tells agencies, and the industries, and the communities about the clarity and the consistency that we’re going to need to plan long-term to meet these goals,” she said.
Sen. David Gallegos (R) expressed concern that the bill’s requirements would cause businesses to leave the state. That could be an issue, especially along the state’s eastern border with Texas, he said.
“If they move to Texas, I don’t think we resolve emissions issues,” Gallegos said.
Clean Future Act
Stewart filed SB 520 on Feb. 16, the last day for introducing legislation The initial version of the bill was essentially a blank placeholder. Net zero language was added in a Senate Conservation Committee substitute version posted last week.
Stewart said various groups had been working with the governor’s office on the bill for nearly the last year. But the efforts broke off due to disagreement among groups. As a result, SB 520 is less comprehensive than it could have been, she said.
In addition to the GHG reduction targets, SB 520 would codify the methane waste rule recently promulgated by the state’s Oil Conservation Division. It would instruct state agencies to apply climate equity principles when developing policies and rules.
There would also be requirements for state agencies to report on GHG emissions from sectors under their control and progress made toward meeting reduction targets.
‘A Real Problem’
Representatives of several conservation groups, including Conservation Voters of New Mexico and Western Resource Advocates, spoke in support of SB 520 during Tuesday’s hearing.
Representatives of groups including the New Mexico Farm and Livestock Bureau, the Independent Petroleum Association of New Mexico and the New Mexico Chamber of Commerce spoke in opposition.
Camilla Feibelman, director of the Sierra Club: Rio Grande Chapter, said after the committee hearing that the vote was a disappointment.
The bill “would have been a strong step forward” and would have laid the groundwork for the New Mexico Environment Department to begin rulemaking to help address climate change, Feibelman told NetZero Insider.
Residents are still recovering from the state’s recent fires and floods, which are a clear illustration of climate change, Feibelman said.
“Failure to move a comprehensive climate bill forward is a real problem,” she said.
AUSTIN, Texas — ERCOT CEO Pablo Vegas has laid down his markers to redesign the market, framing the Texas regulators’ preferred design construct as a reliability product that will “incentivize development and preservation of dispatchable generation.”
Vegas told his Board of Directors Feb. 28 that the performance credit mechanism (PCM) — which would retroactively reward dispatchable generation that meet performance criteria during the tightest grid periods with incentive payments — addresses the grid operator’s resource adequacy and operational flexibility challenges.
Vegas said ERCOT needs more dispatchable energy, pointing to a chart that showed demand has grown steadily since 2000. (Vegas likes to say Texas adds a city the size of Corpus Christi — population 317,773 in 2021 — every year.) ERCOT’s peak load cracked the 80-GW threshold last year, a more than 5-GW jump in three years.
ERCOT projects thermal contributions to remain steady while renewables increase. | ERCOT
Some 27 GW of thermal, or dispatchable, generation in the grid operator’s footprint has been shuttered since 2000. During that time, more than 52 GW of renewable energy has been added; almost as much thermal generation has been added, but it nets out to 24 GW of thermal resources when retirements are taken into consideration.
“We’re now getting to a place where the peak demands require the availability of renewables in order to meet the energy needs of Texas and that’s going to continue to grow into the renewable space,” Vegas told the board. “The reality is, we cannot always predict and plan for when renewables will be available. We can’t control when the wind blows and when the sun shines. With both a correlation of extreme peak and very low performance on renewables, then we can be in an area of risk of significant risks.”
Renewable energy’s growth and its potential swings in availability on any given day create operational risks to the grid, Vegas said.
“The more energy that we carry with renewables as the fleet of renewables have been growing meaningfully across the state of Texas, the risk associated with a real time operations grows at the same time,” he said.
Vegas allowed that renewables offer a “tremendous service” as a low-cost energy source, while also filling the demand gap on high-demand days or when fossil generation outages are up. He said the challenge in ERCOT’s energy-only market is that it allows “the zero cost of those renewables to suppress pricing in the overall market.”
“What that has done is it made it very difficult for dispatchable generators to recover a more significant cost profile to build these large power plants, and they don’t have any federal subsidies to help them do that. It makes it difficult for them to make investments in the state,” Vegas said. “We have to fix the market so that we continue to support the long-term reliability of the grid and look to the future and feel confident that we’ll always be able to meet the needs of Texans, regardless of what’s happening.”
The PCM adds a new revenue stream from generators separate from the energy and ancillary services markets, Vegas said, “specifically created to incentivize generators that can perform when needed and can do so when the grid is tight.” (See Texas PUC’s Market Redesign Dominates ERCOT Market Summit.)
ERCOT expects the PCM to increase total energy costs by $460 million a year, adding a “modest” 2 to 3% to customers’ bills. It has projected implementation will take up to four years and cost between $2 million and $4 million.
Critics say the cost could be much higher.
A report released last week by Bates White Economic Consulting for several industrial consumer groups contends the construct will costs billions “without a meaningful improvement in reliability.” The study reviewed consultant E3’s evaluation of the alternative market options, including the PCM, a dispatchable reliability reserve service (DRRS) and a direct procurement mechanism that could be deployed as a last resort should a dispatchable resources’ shortfall be identified in the future.
The Bates White assessment concluded that a DRRS ancillary service will provide additional market signals sufficient to incentivize new dispatchable generation at a fraction of the PCM’s cost. The latter would create a “tortuously complicated system” that adds costs without improving reliability, the report said.
Bates White said ERCOT’s immediate reliability challenge is to ensure operational flexibility to accommodate continuing additions of intermittent renewable generation. It said the energy and ancillary services markets are the appropriate focus for ensuring flexible and cost-effective operations.
Aurora Energy Research’s Oliver Kerr said during a recent conference that the firm’s analysis found the PCM would be “fairly costly,” ranging from $3 billion to $5 billion across various scenarios.
During the latest legislative hearing on ERCOT’s market design before the House State Affairs Committee last week, Texas Industrial Energy Consumers’ Katie Coleman said the PCM means higher costs “without any guarantee we’ll get anything in return.” The construct will simply shift money from consumers to generators, she said.
ERCOT staff is keeping close tabs on the Texas Legislature, where the PCM proposal continues to run into headwinds. The Public Utility Commission recommended the design to the lawmakers in January but will defer to them on the final design.
At the PUC’s direction, ERCOT staff is soliciting input from stakeholders on a proposed bridging mechanism that would retain existing resources and attract new generation until the final market design is developed. The options include a manually settled PCM, procuring more ancillary services, tweaking the operating reserve demand curve, and a backstop reliability service, previously offered by the PUC, to set aside capacity that is only dispatched during scarcity conditions.
“We’re going to look at what options we can do today to continue to operate the grid as reliably as we have and what can we do to try to send signals to the market, potentially to start developing resources today,” Vegas said.
During a first workshop on the bridging construct Friday, Kenan Ögelman, who oversees the ERCOT market’s design and its commercial operations, asked for stakeholder involvement in the process.
“My goal is to have some kind of matrix summarizing the feedback that we received from you such that there is an easy way for board members to tabulate and figure out where there might be some stakeholder consensus,” he said. “Certainly, I want to recommend something that has some broad stakeholder consensus and that meets the commission’s objective.”
A second workshop is scheduled March 15, during which staff will provide feedback on the comments it has received and seek further discussion on each option. ERCOT plans to bring a final bridging solution to the board for its consideration and approval April 18.
