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November 2, 2024

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Utility CEOs See Ongoing Role for Gas, Nuclear in Decarbonization

WASHINGTON, D.C. — Three senior utility executives told state regulators Feb. 27 that natural gas and nuclear power will be essential to the electric generation mix for decades as the industry decarbonizes. 

Speaking at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit, the executives said the industry already has cut carbon pollution in recent decades, while acknowledging the job is far from over. 

“Since 1984, carbon emissions have stayed the same out of our sector, but electricity use has grown 73%,” said Edison International CEO Pedro Pizarro. “If the Obama Clean Power Plan had been implemented, the industry would have not only met it and surpassed it, [but done] so earlier than the plan would have called for. We have more than 40% of U.S. generation today coming from clean carbon-free resources like nuclear, wind and solar.” 

Pizarro, chair of the Edison Electric Institute, said about 50 of EEI’s members have announced long-term carbon cutting goals and most of them call for net zero by mid-century. 

“We’re doing that now in a backdrop where electricity demand is really moving,” he added. 

Southern California Edison had seen 15 years of essentially no load growth, but now it is expecting load to grow by 2% each of the next several years, Pizarro said.

Tennessee Valley Authority CEO Jeffrey Lyash said emissions in the agency’s footprint have fallen 60% from 2005. Now electricity is responsible for only 27% of the emissions in the TVA region. 

“I think we can get the 80% [reduction from 2005 levels] and keep balanced with that energy security objective,” Lyash said. “The challenge is: And then what? How do you decarbonize the rest of the electricity sector? But more importantly, how do you use electricity, which will be one of the prime ways we decarbonize the rest of the economy?” 

Lyash, chair of the Nuclear Energy Institute, said nuclear power will be part of the mix, along with renewables, energy storage, carbon capture and clean hydrogen. 

“It’s just such a 24/7, system-stabilizing resource, I’m not sure how you get there without it,” he added. 

DTE Energy CEO Jerry Norcia, chair of the American Gas Association, said natural gas is going to have a continued role in a clean energy future.

“When I think about natural gas in our industry, it really has been an enabler of decarbonization,” Norcia said. “About 40% of our power generation in the country now comes from natural gas and that’s a fundamental shift from coal, which was the dominant fuel source for power generation in the past.” 

Direct use of natural gas also is popular, with about 189 million Americans using it and 70% supporting its use, he added. 

The electric industry is heavily reliant on natural gas and its use is going to be “valuable and critical for a very long time,” Pizarro said. Even in California, SCE’s modeling has the fuel in continued use. 

“We see California still having about 40% of the commodity that’s flowing today; it will still be flowing in 2045 economywide,” he said. “For the electric power sector for generation we still see between 4 and 5% of the electrons coming from natural gas-fired resources in 2045.”

Those power plants occasionally burning natural gas in 2045 will have their emissions captured, or at least offset, through “other carbon-negative tools.” Beyond gas, California will need other technologies such as nuclear and eventually offshore wind, which produces power when other renewables do not. 

One major issue is whether EPA should complement the Inflation Reduction Act’s incentives with requirements to shut down fossil-fired plants. Pizarro noted that EEI supported the agency when West Virginia and others sued it to stop the Clean Power Plan.

“But we need to make sure that those regulations are fair and reflect reality,” said Pizarro. 

Some rules requiring natural gas plants to implement carbon capture or burn clean hydrogen were too stringent based on the development of those technologies, he added. Pizarro was speaking days before EPA announced it would delay regulations impacting existing natural gas plants under its power plant rule, focusing it on coal and new natural gas. (See EPA to Strengthen Emissions Regs for Gas Power Plants.) 

EPA Principal Deputy Assistant Administrator for the Office of Air and Radiation Joseph Goffman spoke at NARUC a day before the three trade group chairmen, saying that once the agency issues its final rule on power plants, attention will shift to the states. 

“The main driver will be the state plans, that’s where the action is going to be,” Goffman said. 

As states issue plans to implement the power plant rules, EPA wants to stay in touch with the economic regulators represented at NARUC along with their environmental regulators, energy offices and legislators, he added. 

“That’s where the opportunity will really come to ensure that the rules achieve the urgently needed CO2 reductions from the power sector,” Goffman said. “And at the same time continuing to meet the objectives of a reliable supply of affordable electricity.” 

Goffman was speaking alongside a group of state regulators and West Virginia PSC Chair Charlotte Lane. Lane, whose state still is 88% coal-powered without plans to shut anything down until at least 2040, often sparred with him. 

“Carbon emissions may be a concern,” Lane said. “But they are not the existential threat to life on this planet that some people would have us believe. I am concerned that the EPA has set its sights on a … target is not going to let up until it shuts down all fossil fuel power plants. However, I believe that the cost of an unreliable power supply will be huge and well in excess of any benefits achieved.”

She asked whether the EPA was considering giving a longer timeline for fossil power plants needed for reliability. Goffman answered yes, saying commenters had made the case for the need to be flexible. 

“We sort of see the question of time horizon as part of a larger fabric of flexibility,” Goffman said.

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SPP: Integrated Marketplace Yields $10.2B in Savings

SPP marked the 10th anniversary of its day-ahead, real-time Integrated Marketplace by saying it has provided more than $10.2 billion in savings to members since its launch in 2014. 

The grid operator said the market’s value “far surpassed” initial expectations, noting initial studies projected the marketplace would deliver up to $100 million in annual benefits to its 14-state footprint. In its first year, the market delivered $380 million in net savings, and in just four months, it covered its development costs, SPP said. 

In 2023 alone, the Integrated Marketplace provided the RTO’s members with $2.25 billion in savings, the grid operator said. 

The Integrated Marketplace replaced SPP’s seven-year-old energy imbalance market. It combined SPP’s 16 legacy balancing authorities into a consolidated BA and added congestion-hedging components. The market became financially binding for its initial 103 participants at 12:05 a.m. March 1, 2014. 

“The Integrated Marketplace is an important tool in SPP’s toolbelt,” CEO Barbara Sugg said. “It allows us to provide low-cost, reliable generation and additional economic benefits to the region.” 

The market also was expected to facilitate the further integration of renewable resources in SPP’s region.  

Heading into last summer, the RTO had 32.22 GW of nameplate wind capacity, but only 1.4 GW of solar capacity. However, SPP’s interconnection queue includes 37.51 GW and 24.29 GW of solar and wind projects, respectively, and an additional 20.98 GW of energy storage projects.  

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Whitehouse: Best Defense for IRA is Funding, Building More Projects

WASHINGTON, D.C. ― Sen. Sheldon Whitehouse (D-R.I.) is bullish on CBAM, the European Union and United Kingdom’s adoption of a carbon border adjustment mechanism, which he believes could finally push the U.S. Congress to put a price on carbon. 

The CBAM (pronounced “see-bam”) will levy a price on the carbon dioxide emitted in the production of goods imported into the EU and U.K., in essence a tariff, if the carbon has not been accounted for in the country of origin. Adopted in 2023, the EU CBAM is scheduled to go into effect in 2026. The U.K. pledged to adopt its own version by 2027 at the recent UN Climate Change Conference in the United Arab Emirates. 

“That means the American products being exported into the EU or the U.K. will pay a tariff for the relevant carbon inefficiency of their manufacturing,” Whitehouse said in a keynote speech at the American Council on Renewable Energy’s Policy Forum on Feb. 29. “Which gives a very, very strong motivation to those industries to come to Congress and say, ‘Hey, lift this tariff. … I don’t want to have this collar around my neck when I’m trying to compete in the EU and the U.K.’ And the only way to get that collar lifted is with a domestic carbon price.  

“So, there’s finally, finally, finally going to be some industry counterpressure against the fossil fuel industry in Congress, and that could be the tipping point that will help us move toward carbon pricing.” 

One of the Senate’s strong liberal voices on climate change, Whitehouse repeatedly slammed the fossil fuel industry for its campaign of “climate denial and propaganda … run through multiple dozens of phony friends groups.”  

“The more [we} can find a way to call that out, the easier it is for the public to understand that, no, actually the wind turbines off Rhode Island are not killing the right whales, and that information comes from a source they should not trust.” 

Having clear information “can help change public opinion in these localized debates,” he said, referring to the rise in local opposition to renewable energy projects. 

But Whitehouse also criticized President Joe Biden for not making better use of his “bulliest of pulpits” to counter industry misinformation, for example, pointing to the Securities and Exchange Commission’s proposed rule on corporate disclosure of climate-related risk.  

As reported by Reuters, pushback from corporate interests and state officials may have resulted in the SEC dropping a key provision of the proposed rule, requiring U.S. corporations to report the greenhouse gas emissions from their supply chains, called Scope 3 emissions. 

“Some significant financial companies have retrenched … on their [environmental, social and governance efforts], Whitehouse said. “Their complaint about ESG … is never the S; it’s never the G. It’s always the E, and the E it always is is fossil fuel.” 

The fossil fuel “roadshow” against the disclosure rule and the lack of more outspoken support from the White House has caused agencies such as the SEC “to pull their ambitions in a little bit,” he said.  

The commission is set to vote on the rule at its March 6 meeting. Responding to a query from NetZero Insider, an SEC spokesperson declined to comment on the Reuters report, framing it as “speculation about what may be in or out of a rulemaking.” 

The IRA Tipping Point

The upcoming election and defending the Inflation Reduction Act against former President Donald Trump’s potential return to the White House have become increasing concerns at industry events like the ACORE forum. 

In an on-stage conversation with Lesley Hunter, ACORE’s senior vice president for policy, finance and ESG, Whitehouse likened Republican calls to repeal the IRA to their previous attempts to repeal the Affordable Care Act passed in 2010, the massive health care law widely referred to as “Obamacare.”  

Republicans made several attempts to repeal the law while Trump was in power, Whitehouse recalled, “until a certain tipping point of constituents were enjoying the benefits of Obamacare … and you kind of had to live with it.” Now, with projects funded by the IRA spreading across blue and red congressional districts, “it would be hard for a member to go back and vote against the IRA after they attended the ribbon cutting for a significant project.” 

The best defense for the IRA is to go on announcing and building projects, he said. “Have ceremonies and invite public officials and let them know it came through the IRA.” 

At the same time, Whitehouse gave the IRA and Biden’s executive actions on climate change mixed reviews. The law has been a “terrific success,” he said, but details of implementation, and the law’s durability, may depend on moving rules through a federal bureaucracy where speed still can be slowed by one recalcitrant official or agency. 

The Biden administration’s rule requiring federal agencies to include the social cost of carbon in project cost estimates is another step toward carbon pricing, as is the IRA’s fee on excess methane emissions, Whitehouse said. Their impact, however, may depend on how rigorously individual agencies implement both measures. 

Looking at the social cost of carbon, “you need to be making sure agency by agency that they are following [administration] guidance and actually setting up the decision making in their power purchase contracts and agreements,” he said. 

EPA issued a proposed rule in January on methane charges ― to be imposed on oil and gas facilities emitting more than 25,000 metric tons of carbon dioxide per year ― with a comment period ending March 26.  

The proposed rule does contain provisions that would allow exemptions for some oil and gas companies. Echoing concerns of environmental and clean energy advocates, Whitehouse urged EPA to avoid any loopholes, “responding like firefighters to smoke coming out of a building, and getting the damn thing shut down, and not with fire hoses but with lawyers.” 

Permitting Update

Whitehouse also gave an update on bills he has introduced aimed at streamlining the siting and permitting of interstate transmission and offshore wind. 

“Continued progress” is being made, he said, to reconcile the Streamlining Interstate Transmission of Electricity (SITE) Act, which he introduced in March 2023, and Sen. Martin Heinrich’s (D-N.M.) Facilitating America’s Siting of Transmission and Electric Reliability (FASTER) Act, introduced in June. 

Both bills would give FERC expanded authority for permitting interstate transmission lines. While chances for a general permitting bill are low, Whitehouse remains hopeful that “if circumstances are right, [a transmission permitting bill] could move fairly quickly; so, we want to be ready for that.” 

His offshore wind bill ― the tortuously named Create Offshore Leadership and Livelihood Alignment By Operating Responsibly And Together for the Environment (COLLABORATE) Act ― was released in draft form in January for comment. The bill aims to streamline permitting by frontloading “disputation,” Whitehouse said. 

The goal is to “bring in the real people who are going to be affected by [an offshore project], so you can get off to a much faster start and not find your opponents lurking in the weeds through the long administrative process,” he said. 

“We’re pretty close to landing the final text, but we’re wide open to further amendments,” Whitehouse said. “Then the question is what’s the vehicle?” The best chance could be attaching COLLABORATE to either a must-pass bill or some kind of bipartisan consensus package, he said.  

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EPA to Strengthen Emissions Regs for Gas Power Plants

EPA is holding off on new emissions restrictions for existing natural gas-fired power plants. 

The agency in May 2023 proposed stronger greenhouse gas pollution standards for new and existing fossil-burning generation facilities and received more than 1.3 million comments in response. (See EPA Proposes New Emissions Standards for Power Plants.) 

The process had been nearing its conclusion but will now continue. 

EPA will soon send a finalized version of its proposal to the Office of Management and Budget, but the rules will not cover existing gas facilities — EPA said Feb. 29 it wants to strengthen provisions that pertain to existing gas. 

EPA Administrator Michael Regan said in a news release: 

“As EPA works towards final standards to cut climate pollution from existing coal and new gas-fired power plants later this spring, the agency is taking a new, comprehensive approach to cover the entire fleet of natural gas-fired turbines, as well as cover more pollutants including climate, toxic and criteria air pollution.” 

Gas-burning plants are cleaner than coal-burners, but they do produce emissions and are more numerous. The Energy Information Administration tallied 2,073 gas-burning plants rated at least 1 MW nationwide in 2022 and only 242 coal-burning plants. 

Some Republicans and industry groups criticized the original emissions proposal as strict and potentially damaging to grid reliability, which EPA denied. (See Regan: New EPA Standards Designed to not Jeopardize Grid Reliability.) 

In contrast, some environmental advocates criticized the original emissions proposal as too lenient, saying it would have applied to only a small percentage of existing gas-fired plants. 

This sentiment was captured in a celebratory quote EPA provided Feb. 29 from Washington Gov. Jay Inslee (D):  

“This is excellent news from Administrator Regan, and I commend him for his continued leadership. We cannot mitigate emissions and pollution from power plants by ignoring our country’s largest source of electricity generation: existing gas plants. Washington state is eager to support EPA in undertaking this rulemaking as quickly as possible.” 

Some environmental advocates offered messages that were more wait-and-see than celebratory. 

NRDC President Manish Bapna said in a prepared statement:  

“We can’t tackle climate change and clean up air pollution without slashing emissions from the existing gas-fired power plants already pumping huge amounts of carbon and other dangerous pollutants into the air. EPA needs to finish the job without delay.” 

Peggy Shepard, executive director of WE ACT for Environmental Justice, said:  

“We are wholly appreciative of EPA’s leadership in demonstrating the need for further review, and at the same time request a clear and transparent process as we look forward to collaborating for its improved realization. Only when this rule is finalized can we truly know we are on a path to resilience and justice.” 

Regan touched on these concerns in EPA’s news release: 

“This stronger, more durable approach will achieve greater emissions reductions than the current proposal. EPA proposals on criteria pollutants and air toxics also will help address local air quality impacts to better protect vulnerable frontline communities. 

“This comprehensive approach to reducing climate and air pollution will also consider flexibilities to support grid operators and will recognize that ongoing technological innovation offers a wide range of decarbonization options. EPA will immediately begin a robust stakeholder engagement process, working with workers, communities with environmental justice concerns and all interested parties to help create a more durable, flexible and affordable proposal that protects public health and the environment.” 

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Grain Belt Express Gets Partial Approval for Negotiated Rate Authority from FERC

After a fresh FERC review, Invenergy has walked away with half the authorizations necessary to charge negotiated rates for transmission service on its $7 billion, 5-GW Grain Belt Express transmission project.  

Late last year, Invenergy sought FERC permission to amend its negotiated rate authority for Grain Belt Express because the merchant transmission project’s design had changed substantially since FERC originally granted authority in 2014 (ER24-59).  

FERC scrutinized the project using its four-factor test. The commission said while Grain Belt satisfied its requirements for just and reasonable rates and regional reliability, it lacked information on whether Grain Belt would parcel out capacity on its line fairly.  

“We reserve judgment on whether Grain Belt’s capacity allocation process satisfies the commission requirements for undue discrimination and undue preference (factors two and three). We will make a determination regarding those factors at such time as Grain Belt submits a filing providing sufficient detail to evaluate whether its capacity allocation process satisfies the commission’s requirements, either in advance of its open solicitation or post-open solicitation,” FERC wrote in a Feb. 29 order.  

FERC said while Invenergy requested “flexibility” for its upcoming capacity allocation process, it provided only “limited detail on the selection process or selection criteria for the commission to evaluate.” The commission said it couldn’t be confident Invenergy would not bestow undue preference on generation affiliates when selling the line’s capacity.  

Invenergy said last year it intends to launch an open solicitation for takers of capacity on the first, 2.5-GW phase of the line, which runs from Kansas to Missouri. In its filing, it said it has hired the Brattle Group to serve as an independent consultant and oversee the open solicitation for a “portion of capacity for Phase 1.” Invenergy said the Brattle Group will develop selection criteria and ensure the solicitation is conducted in a transparent and non-discriminatory manner. Invenergy also promised a post-solicitation compliance filing to FERC.  

The Missouri Joint Municipal Electric Utility Commission already has agreed to buy up to 225 MW of capacity on Grain Belt.  

The Missouri Landowners Alliance protested Invenergy’s request to amend its negotiated rate authority and said the commission should require Invenergy to reapply for permission to offer capacity on Grain Belt at negotiated rates. The landowners argued that project ownership, capacity and interconnection points have changed too drastically since FERC originally granted Grain Belt’s negotiated rate authority. 

Invenergy acquired development assets for Grain Belt from Clean Line Energy Partners in 2018. The Missouri Landowners Association argued Invenergy didn’t notify FERC of the handover and the expansion of the project. (See Invenergy Announces Grain Belt Express Expansion.)  

The association also voiced concern that Invenergy “controls a large inventory of energy facilities,” including generation, and suggested it could give its affiliate customers preferential treatment or have an incentive to withhold capacity. It cautioned FERC that Grain Belt’s “use of an independent evaluator should not take the place of regulatory scrutiny and guidance.” 

Invenergy rebutted that FERC rules don’t allow it to unduly discriminate or show undue preference in the open solicitation process. 

The association also accused Invenergy of beginning negotiating capacity sales ahead of its future open solicitation. Invenergy said the Missouri landowners’ allegation was incorrect and based on the association conflating sales of transmission service with a sale or lease of an undivided interest in Grain Belt.  

FERC didn’t address the debate because it left those sections of the four-factor test undecided. 

The Sierra Club in late October wrote to support negotiated rate authority for Invenergy.  

“The Grain Belt Express Project will lower electricity costs for consumers, markedly improve the economic operation of these regional electric grids, offer significant resilience value — especially during storms and other high-demand events — and improve resource adequacy for customers and utilities,” the environmental group said. 

Invenergy plans to begin construction on Grain Belt in early 2025 and has said it already secured 95% of the land necessary for Phase 1 of the project. The Kansas-to-Illinois line will connect SPP, Associated Electric Cooperative, MISO and PJM. Invenergy has selected Siemens Energy to provide the HVDC technology for the first phase of the 800-mile line. 

Invenergy said it expects to put separate filings for approval before FERC to transfer Phase 1 capacity to buyers and/or lessees via sales and/or leases of undivided interests in the transmission line. Those require individual approvals.

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MISO Wants $10K VOLL, a Nearly Threefold Increase

CARMEL, Ind. — MISO last week said its extensive analysis shows that its current $3,500/MWh value of lost load (VOLL) should be raised to $10,000/MWh.  

The grid operator has made a renewed push in recent months to re-estimate its value of lost load after saying that its existing VOLL is dated, having been established in the 2008-2009 time frame. MISO’s current VOLL reflects the willingness of the lowest-income residential customers in the RTO’s footprint to pay for uninterrupted service.  

During a Feb. 29 Market Subcommittee meeting, MISO’s Chuck Hansen said the $3,500/MWh limit “can currently curtail valid market prices.”  

“When the system is in a more vulnerable state, prices should reflect the risk of diminishing reserves,” Hansen said.  

Three years ago, MISO’s Independent Market Monitor recommended the RTO adopt a $10,000/MWh VOLL.  

Hansen likened a well-thought-out VOLL to the “jolt” delivered from farmers’ electric fences, which aren’t meant to injure livestock.  

“The goal isn’t to shock the cows; the goal is to just keep them in the field,” he explained. 

Hansen said a raised value would almost counterintuitively moderate market volatility because market participants would take more actions to dodge the highest prices.  

“With higher prices, we expect lower volatility and more preparation to avoid those kinds of real-time energy deficiencies,” he said.  

Hansen said MISO’s current VOLL is “outdated and below industry willingness to respond to demand.” He said a reasonable VOLL would properly discourage market participants from “these ‘touching the electric fence’ situations” and “potentially make them more rare than they already are.” 

New VOLL Means New ORDC

MISO said it also will seek to change how VOLL ties into its operating reserve demand curve (ORDC). MISO’s ORDC is linked to VOLL, and the current curve mostly sits at $1,100/MWh and $2,100/MWh across two large steps before it tops out at $3,500/MWh.  

Despite proposing a $10,000/MWh VOLL, MISO wants its ORDC to peak at $6,000/MWh and stay there until about 50% of cleared operating reserves materialize. From there, the curve would slope downward until MISO can confirm more than 80% of its cleared operating reserves, at which point the curve would become two steps: $1,100/MWh until 88% of reserves show up and $600/MWh until 100% of reserves turn up.  

If MISO already had the new curve in place, Hansen said more than 90% of MISO’s past shortages would have resulted in lower penalty prices. Most of the RTO’s operating reserve shortages occur at 88% of reserves or higher. Historically, MISO has never experienced an operating reserve shortage below 50%.  

“This is not just about raising VOLL and making prices higher. On the right side of the curve, we thought it was appropriate to lower prices,” Hansen said. 

Hansen said MISO would like to introduce an ORDC that is lower for small reserve shortages and results in higher prices for greater shortages.  

“As reserves go away, we want prices to approach VOLL, but we don’t want prices to be so high that they reach VOLL well before load shedding is initiated,” Hansen said. Conversely, he added that the lower bound of the ORDC shouldn’t be so low that it’s cheaper for market participants to violate marketwide operating reserve requirement.  

Hansen said MISO wants to continue to use an updated VOLL as a price cap for locational marginal prices, market clearing prices and during load shed events.  

But he said MISO would like to sever the connection between VOLL and MISO’s emergency demand response offer cap. MISO has called on its emergency demand response only once, more than 15 years ago. Today, MISO’s emergency demand response averages less than 500 MW and is managed on a separate system from the RTO’s markets. The product was introduced before MISO debuted its ancillary service market, and owners are under no obligation to be available. Hansen said MISO has debated retiring its emergency demand response product and urges market participants to move their offerings under the RTO’s existing load-modifying resource and demand response programs.  

MISO’s proposed ORDC. The ‘SOM’ curve refers to the Independent Market Monitor’s past recommendation for a new curve. | MISO

Justification for $10K

Hansen said the current VOLL was established alongside the launch of MISO’s ancillary services market and “that number has not changed in 15 years.”  

He said MISO has made hundreds of calculations to freshen its VOLL, including crunching numbers for different lengths of outages; nonsummer versus summertime periods; afternoon, evening or off-peak periods; and using different customer load classes, including small commercial, industrial, residential and manufacturing segments.   

MISO found that for a one-hour outage occurring off-peak in summer, VOLL will run $4,337/MW for residential customers and up to nearly $81,000/MW for small commercial and industrial customers. For an eight-hour outage occurring off-peak in summer, a residential VOLL will run about $8,107/MW, while small commercial and industrial customers’ value runs more than $266,000/MW.  

“We’ve been studying a range of numbers, many numbers,” Hansen said.  

MISO found that its highest VOLL occurs during off-peak periods with small commercial and industrial customers the most exposed to risks of lost revenue. Larger commercial and industrial customers often have access to more capital to prepare to bounce back more quickly from an outage, staff said.  

When MISO made its 2007 FERC filing to create VOLL, it used the average of the $1,470/MWh median value of its residential class and the $15,250/MWh lowest median value of the small commercial and industrial class. The resulting VOLL was weighted 85% toward residential customers.  

Using that same 2007 calculation, Hansen said the 2023 VOLL for a summertime, one-hour outage occurring off peak should be $13,640/MWh.  

“What we’re proposing is actually on the conservative side,” Hansen said.  

Hansen reminded stakeholders that MISO isn’t in charge of which customers are affected by outages when it orders load shedding. The RTO simply tells local balancing authorities how many megawatts it needs off the system. MISO said a recent survey of its local balancing authorities shows that when instituting rolling blackouts, customers dropped on average are 48% residential, 30% large commercial and industrial, and 22% small commercial and industrial.  

Hansen said a $10K VOLL reflects that industrial customer load is also shed alongside residential load during dire circumstances. 

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MISO: New Capacity Accreditation Filing Imminent

CARMEL, Ind. — MISO is determined to file with FERC by the end of March to introduce a probabilistic capacity accreditation that’s controversial among stakeholders.  

MISO stakeholders continued to lobby for a deferral during a Feb. 28 Resource Adequacy Subcommittee meeting, again telling the RTO it hasn’t shared enough information on its loss of load-oriented accreditation style. (See MISO Set on March Accreditation Filing, Stakeholders Push for Slowdown.) A filing in March seems destined to gather several protests.  

But Senior Manager of Market Design Neil Shah said MISO has now shared enough data from its analyses to give stakeholders a “broad indication” of their future capacity credits to adjust generation plans accordingly.  

“The filing needs to happen now for stakeholders to make those adjustments,” Shah said.  

MISO doesn’t intend the accreditation to take effect until the 2028/29 planning year. 

Shah said “the beauty of” MISO’s method is that it measures the reliability contribution of all resources across “hundreds and hundreds” of simulated risky hours. 

Under the new method, generators’ capacity credits would be determined by a combination of individual past performance and resource-class average performance during hours with tight conditions and modeled loss-of-load hours for different types of generation. Most resources’ credits would shrink under the new accreditation. Resources would be divided by fuel type: gas, coal, hydro, nuclear, energy storage, pumped storage, wind and solar. MISO at first didn’t commit to listing resource types in its tariff filing with FERC.  

Shah likened MISO’s accreditation change to his homeowner’s insurance policy recently increasing by a few hundred dollars based not on him, but on his neighbors filing more claims recently. He said his insurer took the growing claims as proof of rising risk in his neighborhood and reassessed. MISO, Shah said, is no different with this new accreditation direction.  

Many MISO stakeholders have argued the loss-of-load accreditation would inject too much uncertainty into the MISO market, disrupting integrated resource plans and investment decisions. At the RASC meeting, some said they don’t have adequate insight into how capacity credits would differ by resource type and questioned whether MISO’s proposed resource classes would sufficiently represent all types of resources in MISO.  

Shah said MISO is prepared to make a future filing if new technology necessitates the RTO add new resource classes but said MISO has landed on a “good representation of resources classes” in the footprint today.  

Shah also noted that during the three-year transition period, MISO wouldn’t apply the accreditation but would publish indicative accreditation results for resource classes, as well as anticipated local reliability requirements and planning resource margin requirements based on the direct loss-of-load accreditation method. MISO wouldn’t share unit-level capacity values publicly; market participants would need to request those from the grid operator.  

MISO has said the new accreditation would better ensure seasonal reserve requirements are met, shape long-term investment and retirement decisions “by accurately representing the capacity value of a resource in the prompt year,” and incentivize resources to show up during times of the greatest system need. It has characterized the new accreditation style as a “consistent accreditation methodology for all resources, capturing the reliability contribution during times of highest risk.”  

MISO’s Zak Joundi has said MISO members would “have plenty of time to adjust” to the new rules.  

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MISO Names New Chief Information Security Officer

MISO announced it has promoted Eric Miller to chief information security officer and the RTO’s newest vice president.  

Miller joined MISO in 2020 as an executive director of digital technology. Prior to signing on with MISO, Miller held IT and cybersecurity leadership roles at Ascension Technologies, the health care company’s IT division.   

Miller is based out of MISO’s Carmel, Ind., headquarters and is now responsible for managing the RTO’s physical security, cybersecurity, and technology infrastructure and operations. 

“I look forward to stepping into this new role at MISO,” Miller said in a March 1 press release. “I’m excited about leading a world-class team of professionals who are committed to a safe, secure and reliable bulk electric system.” 

Former Chief Information Security Officer Keri Glitch left MISO last year to join Fortis, where she serves as the vice president of information technology.  

Miller has a master’s degree in systems engineering from Johns Hopkins University and a Master of Business Administration from Bowling Green State University. He also was a commissioned officer in the U.S. Army.  

MISO said Miller recently completed the CISO Executive Education and Certificate Program from Carnegie Mellon University’s Heinz College of Information Systems and Public Policy, in addition to holding multiple other cybersecurity certifications.  

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Bill to Link Wash. Cap-and-trade with Calif.-Quebec Passes Both Houses

Washington’s Democratic-controlled House of Representatives on Feb. 29 approved a bill that would allow the state’s cap-and-trade program to link up with the system shared by California and Quebec.  

Senate Bill 6058, sponsored by Sen. Joe Nguyen (D), passed the House 57-39 along party lines — just as it did in the Senate earlier this month. (See Carbon Market Linkage Bill Passes Wash. Senate.) 

The two houses must now reconcile minor changes added to the bill.  

Washington is negotiating with California and Quebec on potentially meshing their cap-and-trade programs with the expectation that a bigger market would soften carbon allowance prices, which then could reduce the state’s high gasoline prices.  

Linkage between the markets could take place no earlier than 2025. Looming over the development is a November referendum on whether to repeal Washington’s cap-and-invest program, which some have blamed for the state’s gas price increases.

House Republicans opposed the bill Feb. 29, spending the majority of a four-and-a-half-hour debate slamming cap-and-invest for boosting gas prices. When focused on the specifics of SB 6058, Republicans said they did not like tying Washington’s program to the much larger California one, which see its own unique ups and downs. They also voiced skepticism about claims that a larger market would decrease gas prices in the Evergreen State. 

“We’re going into an agreement without a clear understanding of the partners we want a relationship with,” Rep. Keith Goehner (R) said.  

“Fools rush in. We should not rush into any linkage,” said Rep. Jim Walsh (R), who is also one of the leaders of the initiative to repeal cap-and-invest. 

Majority Leader Joe Fitzgibbon (D) pointed out that a common argument against Washington’s efforts to combat climate change is that one state’s efforts won’t affect global warming. He said a carbon market combining Washington, California and Quebec would create a greater effect on reducing emissions. And Fitzgibbon noted that New York, Massachusetts and Maryland are watching Washington’s efforts with the idea of creating their own cap-and-trade programs to eventually join the bigger market. 

The bill “simply sets us up for success as we work with California and Quebec collectively to protect our air sheds from greenhouse gases,” said Rep. Beth Doglio (D).

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‘Bigger Stuff’ is Coming for SPP’s REAL Team

DFW AIRPORT, Texas — SPP’s Resource and Energy Leadership (REAL) Team last week marked the one-year anniversary of its formation with yet another discussion of resource adequacy issues and the various metrics used to determine a reliability standard. 

But not to worry. Major developments are on the horizon. 

“The bigger stuff is coming later,” said SPP’s Casey Cathey, senior director of grid asset utilization, following the Feb. 21 meeting. 

That would be the winter planning resource margin (PRM) and a reliability standard based on expected unserved energy (EUE). However, it may take time. 

“I think we need some time to bake in more of an understanding about the interrelationship between EUE and the fuel mix, as well as the load changes,” Cathey said. “We do need to work towards an accelerated standard, but we’ve never enforced an EUE limit before. It’s always been PRM. As we’re continually seeing the fuel mix change and the loads are also under a lot of scrutiny, with more resources that are underperforming and more extreme events, I think the fear is to put a standard without it being potentially well thought out could be extremely costly.” 

To ease that fear, the REAL Team contracted last year with firms 1898 & Co. and Astrape Consulting to conduct a future resource mix study. The study focused on five- and 10-year projections for PRM and renewable resources’ effective load-carrying capability values as providing better forward-looking information than the standard loss-of-load expectation (LOLE) studies. 

It also considered EUE as a new metric, given resource adequacy’s shift from “capacity adequacy” to “energy adequacy.” SPP staff said they have found a divergence in EUE and LOLE as the system evolves more toward an “energy-limited” resource portfolio. 

The study found the existing 0.1 LOLE reliability target continues to contribute to an increased EUE and “unacceptable reliability” and that as renewable capacity increases, the winter season becomes dominant. Implementing reliability metrics separated by season helps meet the annual LOLE/EUE target, it said. found the existing 0.1 LOLE reliability target continues to contribute to an increased EUE and “unacceptable reliability” and that as renewable capacity increases, the winter season becomes dominant. Implementing reliability metrics separated by season helps meet the annual LOLE/EUE target, it said. 

However, the study found a last-in allocation methodology “may allocate more accreditation than appropriate to certain technology types due to synergies between resources. It said more studies are required to confirm the appropriate level of a normalized EUE as a reliability standard. 

“We have a natural breakdown that winter events are longer, deeper and they have more amounts of energy per event than you do in the summer,” 1898’s Brian Despard said. “If you add more renewables, you’re shifting from summer events to winter events and there’s naturally more unserved energy in the winter. So, we have to install a standard that says, ‘Let’s keep unserved energy the same instead of keeping the number of events the same.’ We’re going to have a secondary and complementary requirement that says, ‘I will get a credit for the ability to maintain those standards as well.’” 

Brian Despard, 1898 & Co. | © RTO Insider LLC

The REAL Team will continue its discussion of the PRM and EUE metric when it gathers at SPP’s headquarters in Little Rock, Ark, March 22. 

“That’s March Madness,” said Kristie Fiegen, chair of both the REAL Team and the South Dakota Public Utilities Commission and an apparent fan of college basketball’s annual postseason tournament. 

Still, the meeting will go on. 

“More education is needed across the board for members, for the Regional State Committee, for REAL,” Cathey said. 

The REAL Team reports to the RSC, which is composed of SPP state regulators. Also, it is working in tandem with the Supply Adequacy Working Group (SAWG) and the RSC’s Cost Allocation Working Team. 

“We’re kind of working to educate on the EUE, but to also help that education form how we might best establish our very first separate winter planning reserve margin,” Cathey said. “Even though we don’t have a standard — and this is what’s a little bit confusing — we still understand that we shouldn’t just let EUE be this massive number. We have to use the data from the loss-of-load expectation study to best inform how we balance the risk between winter and summer for upcoming 2026 binding season.” 

The REAL Team directed SAWG to consider EUE associated with an LOLE metric to determine winter and summer PRMs, recommend an EUE standard, and place the expectation of that effect on the 2025 LOLE study.  

Evergy’s Colton Kennedy, SAWG’s chair, agreed that more education and analysis is needed.   

“There’s a separate conversation around what [we] are establishing as a region for an EUE standard. I think honestly, we don’t need that to set the PRM, to recommend PRM,” he said. “I think we know that there are gaps. We know that the EUE is something that needs to be incorporated into the target. I don’t think we have enough information to say this is the appropriate risk tolerance for this region.” 

Separately, the team approved a tariff change (RR605) intended to clarify resource availability expectations for both the summer and winter seasons. The measure adds a definition of authorized outages and more requirements for availability during the two seasons when not on an authorized outage, and it clarifies when load-responsible entities and generation owners should submit resource adequacy capacity to meet their requirements. 

“It’s not the most complicated policy, but it’s fairly important. If we didn’t do it, we will be shooting ourselves in the foot,” Cathey said. 

The revision’s language is seen as meeting FERC’s expectation that SPP consider expedited proceedings for any future filings on the winter season RA requirement. The commission in November rejected the grid operator’s first attempt at a winter resource adequacy requirement; the RTO plans to refile the requirement, nonbinding until the 2026-27 winter, in April. (See “FERC Rejects Winter Requirement,” ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.) 

The REAL Team also endorsed a pair of initiatives by staff and stakeholders: 

    • The Market Working Group’s development of potential availability market constructs and other incentive-based mechanisms. The MWG explored five options before determining that, based on staff’s evaluation, a performance credit mechanism (PCM) similar to ERCOT’s and an energy availability market would provide the largest economic and reliability benefits. The group is monitoring ERCOT’s PCM development process and will reevaluate the need for additional mechanisms once resource adequacy policies are implemented and evaluated. 
    • Staff’s pursuit of a price-formation policy that dispatches the system based on the true obligation and prices the system during a scarcity event using the obligation without the effect of load shed and emergency energy assistance. Staff plans to secure approval from stakeholders, regulators and the board in April and May, and then take the revision request to the same bodies in July and August.