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November 12, 2024

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MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report

MISO has released a new edition of its Reliability Imperative report, with the latest version containing an urgent call to action for all MISO players.

“We have to face some hard realities,” MISO CEO John Bear prefaced the refreshed report. “There are immediate and serious challenges to the reliability of our region’s electric grid, and the entire industry — utilities, states and MISO — must work together and move faster to address them.”

The report emphasized that all three must coordinate at once to avoid a “looming mismatch” between retiring baseload generation and an influx of weather-dependent generation. MISO said members should temper retirements to retain some dispatchable “transition resources” as “reliability insurance.” 

MISO first published its Reliability Imperative report in 2020 and has updated it periodically since. It describes the RTO’s risk profile and the steps MISO, members and state regulators should take to mitigate threats. 

In a Feb. 21 press release accompanying the report, MISO said that in addition to “significant changes to the generation fleet, the electric power industry is facing an increase in extreme weather events, large load additions, electrification, supply chain issues, permitting delays and fuel assurance issues.”

Members have cut carbon emissions by about 30% since 2005, and Bear said the footprint could cut them by more than 90% in coming years. 

“Studies conducted by MISO and other entities indicate it is possible to reliably operate an electric system that has far fewer conventional power plants and far more zero-carbon resources than we have today. However, the transition that is underway to get to a decarbonized end state is posing material, adverse challenges to electric reliability,” Bear warned. He said that until new technologies become viable, MISO will continue to need dispatchable resources.  

“We’re seeing traditional generators being replaced by resources that aim to meet clean energy goals but that do not have the same reliability attributes as those they are replacing,” Bear said.  

MISO said supply chain and siting and permitting issues outside of MISO’s control are hampering new generation projects that will be crucial to reliability. The grid operator also said the footprint is increasingly housing single-site, large load additions like data centers that planned and existing generation might not be able to accommodate, especially when considering new pressure on the grid from electric vehicles and other electrification. 

MISO reported that its South region is experiencing an industrial renaissance and soon could add manufacturing plants producing steel, hydrogen, liquefied natural gas and other heavy industry totaling 1 GW in new demand. 

MISO said diminishing generation and load growth over the past decade-plus already have depleted its surplus reserves.

“Since 2022, MISO has been operating near the level of minimum reserve margin requirements,” it said. 

The RTO said ongoing initiatives into 2024 like applying a sloped demand curve in capacity auctions, introducing a capacity accreditation that’s more reflective of actual generator availability and planning a second long-range transmission portfolio should help the footprint make progress toward a more reliable transition.  

MISO President Clair Moeller said MISO sees “very little risk of overbuilding the transmission system; the real risk is in a scenario where we have underbuilt the system.” 

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FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO

FERC is poised to levy $27 million in penalties on a Texas-based LLC meant to sell in-car ketchup holders that collected more than $1 million in undeserved MISO demand response payments.  

The commission issued a show-cause order Feb. 21 to Ketchup Caddy LLC and CEO and owner Philip Mango, indicating it will assess $25 million in civil penalties on Ketchup Caddy, $1.5 million in civil penalties on Mango and order Mango to disgorge $506,502, plus interest, in unjust profits for bogus load reductions unless he can offer an explanation (IN23-14).  

Philip Mango | Jen Mango

FERC’s Office of Enforcement concluded that Ketchup Caddy is a “fraudulent enterprise with no legitimate market activity, registering and clearing demand response resources without their knowledge or consent and collecting capacity payments in turn, without making payments to the registered resources.” Enforcement staff said Mango “made no attempt to contract with — or even to contact — legitimate customers, and the purported customers Ketchup Caddy registered with MISO would not have responded if dispatched.”  

According to enforcement staff, Ketchup Caddy, Mango and co-founder Todd Meinershagen collected more than $1 million in fraudulent capacity payments beginning with the 2019/20 MISO capacity auction. In doing so, the company denied other MISO suppliers the opportunity to earn more than $17.6 million because its fraudulent offers suppressed capacity prices in the 2019/20, 2020/21 and 2021/22 MISO Planning Resource Auctions. The company received weekly capacity payments until October 2021, when MISO became aware of the scheme and removed Ketchup Caddy from its capacity market.  

Mango admitted to having no intention of enrolling actual customers, FERC staff said, and neither he nor Meinershagen attempted to defend their actions.  

Meinershagen already agreed to pay more than $525,000, including interest, for his role in the market manipulation as part of a December 2022 settlement agreement.  

Meinershagen, a computer programmer, reportedly used a random number generator on an Ameren website to land on actual customer accounts and “scrape” customer data. Staff said it was Mango’s responsibility to contact customers and convince them to participate in a demand response program with zero payout to them and 100% going to Ketchup Caddy. Mango said he never contacted potential demand response customers and never attempted to draft contracts because there was no way customers were going to agree to accept nothing. By early 2019, he had run out of time and fraudulently registered unwitting customers.  

“We were accepted in late February and had 48 hours to load customers into the MISO program before it closed,” Mango said of his experience registering demand response with MISO.  

FERC staff said Ketchup Caddy cleared 211.1 MW in the 2019/20 MISO capacity auction, 303.2 MW in the 2020/21 auction and 372.3 MW in the 2021/22 auction. The commission said Ketchup Caddy’s false registrations and offers went under the radar because MISO didn’t order curtailment in any of those planning years and only required “mock tests to verify performance.”  

Mango said he was looking for “essentially free money, no harm to the customer” and told staff that he planned to“[d]o this for just a couple of years, make a bunch of money to put kids through school and do all those things, and no one’s hurt. Do it with the least amount of resource possible, the least amount of money invested.” 

Mango reportedly admitted that his company didn’t provide any value to the MISO market and any “reasonable person” would conclude that his actions were illegal. Mango also said he kept Meinershagen in the dark” and created a “mirage” to make him believe that Ketchup Caddy was legitimate.  

“Upon further reflection, I realize the egregiousness and the error of my ways,” he told FERC staff.  

Ketchup Caddy’s LinkedIn page routes to a distributor page for Plexus, a multilevel marketing company that deals in dietary supplements. MISO recognized Ketchup Caddy as a market participant in late 2018. The Frisco, Texas-based company was originally created by Mango to sell an in-car ketchup holder he invented.  

FERC gave Mango 30 days to respond to its order. Mango can choose between a prompt penalty assessment, or he can plead his case at an administrative hearing before an administrative law judge.  

This is the third time companies have been caught manipulating MISO’s demand response program and collecting unjustified payments, with penalties set to reach several million dollars.  

In January, FERC’s Office of Enforcement found that an air separation facility in Indiana accepted payments for phantom load reductions. It ordered Northern Indiana Public Service Co. and the U.S. arm of U.K.-based chemical company Linde Inc. to pay $66.7 million to settle charges it gamed MISO’s demand response program. In that case, FERC found that Linde’s Calumet Area Pipeline Operations Center in northwest Indiana would operate some equipment in the facility needlessly and vent gases it distilled back into the atmosphere, solely for the purposes of raising its registered baseline electricity use with MISO. (See FERC Orders $66.7M in Penalties and Disgorgement on Linde and NIPSCO.)  

Last year, FERC ordered an Arkansas steel mill and Entergy Arkansas to return a $35 million settlement for the steel mill’s yearslong failure to reduce electricity use as a demand response resource. Soon after, MISO’s Independent Market Monitor recommended the RTO implement demand response offer floors and attestations of expected levels of energy consumption to ward off similar DR schemes in the future. (See IMM Presses MISO for New Rules After DR Market Gaming.)  

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Prices, Renewables Rise in New England Capacity Auction

[Editor’s Note: This story was updated to correct some details of the capacity awards.]

ISO-NE’s capacity market continued its rollercoaster ride as prices for Forward Capacity Auction 18 rose to $3.58/kW-month, a nearly $1 increase (38%) over last year and the second highest “Rest-of-Pool” price since FCA 13. 

The RTO, which completed the auction after four rounds of bidding on Feb. 5, filed its results for FERC approval Feb. 21 (ER24-1290). The RTO asked FERC to set a deadline of April 8 for comments.  

The auction for the June 1, 2027-May 31, 2028, delivery year procured 31,556 MW of capacity — slightly above the 30,550-MW net installed capacity requirement (ICR) — from about 950 resource obligations, ranging from 7 kW (Sunnybrook Hydro 2) to the Seabrook and Millstone Point Unit 3 nuclear plants at 1.2 GW each. The capacity will cost ratepayers about $1.3 billion. 

Last year, prices cleared at $2.59/kW-month in all zones and import interfaces except for the New Brunswick interface, which cleared at $2.551. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.) 

ISO-NE’s calculation of the quantity of capacity procured is based on the amounts for June 2027. Among fuel types, natural gas led with 13,817 MW (44% of the total), followed by fuel oil and nuclear at 11% each, and hydropower at 10%.

Demand response contributed 2,614 MW (8%), followed by electricity used for energy storage (5.8%)

Solar (2.2%) and wind (1.7%) trailed kerosene at 3%, although their combined total of 3.9% was up from about 3% in last year’s auction.

Imports contributed 1.5%.

New resources represented 1,484 MW, 4.7% of the total, including 741 MW of storage, 185 MW of wind and almost 53 MW of solar.

In total, the RTO said, emissions-free renewable generation, storage and demand resources contributed about 40% of the total at almost 1,085 MW. 

ISO-NE capacity demand curve, net installed capacity requirement (net ICR) and net cost of new entry (net CONE) for Forward Capacity Auction 18 | ISO-NE

Zones

The auction set separate zones for Northern New England (New Hampshire, Vermont and Maine load zones), Maine (modeled as a nested export-constrained zone within NNE), and the Rest-of-Pool. 

The ROP included Southeastern Massachusetts, Rhode Island, Northeastern Massachusetts/Boston, Connecticut and Western/Central Massachusetts.  

The descending clock auction started in each zone at $14.525/kW-month, resulting in a clearing price of $3.58/kW-month for all zones and imports over the New York AC ties (122.89 MW), New Brunswick external interface (70 MW), Hydro-Québec Highgate external interface (18.17 MW) and the Phase I/II HQ Excess external interface (253.78 MW). 

There were no active demand bids for the substitution auction and the RTO did not reject any retirement delist bids for reliability reasons.

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Supreme Court Skeptical of EPA’s Good Neighbor Plan

The U.S. Supreme Court’s conservative majority on Feb. 21 appeared inclined to pause the Biden administration’s Good Neighbor Plan, an EPA rule to limit ozone-forming nitrogen oxide emissions from power plants and industrial facilities in certain states. 

The plan was first proposed in 2022, and EPA issued a final rule early last year that applied to 23 states found to be contributing to unhealthy levels of ground-level ozone in neighboring downwind states, making it difficult for those states to meet the 2015 National Ambient Air Quality Standards. 

Lower courts have stayed the rule in 12 states while they consider it, but the agency has continued to enforce it for the remaining 11. The Supreme Court agreed in December to listen to petitions for an emergency stay — consolidating challenges by Ohio, Indiana and West Virginia with those of Kinder Morgan, the American Forest and Paper Association, and U.S. Steel — after the D.C. Circuit Court of Appeals declined to rule on the matter while the lower court challenges proceed. Ohio and Indiana are among the remaining 11 states, while West Virginia is not currently required to comply. 

Several conservative justices focused on whether the plan’s cost calculations are still justified for the remaining states, while liberal justices expressed concern about the precedent the court would set by ruling before the lower courts had a chance to hear the case. 

Representing the states, Ohio Deputy Solicitor General Mathura Sridharan asked the court to pause the implementation of the rule, arguing that “while these [lower court] proceedings are going on, the states and their industries continue to suffer irreparable harm.” An emergency ruling is justified by “the threat of power shortages and heating shortages.” 

EPA’s calculation of the compliance cost threshold was set based on all 23 states, and the agency did not adequately consider how removing states from the plan would affect it, said Catherine Stetson, representing the industry challengers. 

“What happens if you take out the states where maybe you can control those costs most cheaply and you’re left with states that actually have much higher cost thresholds to impose on industries or on” electric generating units? Stetson asked. 

Justice Brett Kavanaugh said the burden is on EPA to show the cost threshold calculated based off all 23 states should still apply to a smaller number of states.  

“The problem is we’re not sure if the requirements would be the same with 11 states as with 23,” Kavanaugh said. “It’s just not explained.” 

But other justices expressed skepticism that a stay in some states justified a re-evaluation for the others, as the compliance costs are fixed and not changed by the exits. 

“If all these lawsuits that the states are bringing are going to end up losing,” said Justice Elena Kagan, “the idea that you can be here and be demanding emergency relief just because states have kicked up a lot of dust seems not the right answer to me.” 

Justice Amy Coney Barrett questioned Stetson on the timing of challengers’ request for the Supreme Court to intervene. 

“You’ve talked about projected injury, projected costs that you’re going to incur, but, presumably, I mean, the rule’s been in effect for a while,” Barrett said. “Why haven’t you talked about that? I think you’re kind of shifting gears now.” 

Stetson responded that EPA’s plan will cause significant costs to power plants over the coming 12 to 18 months, triggering “immediate reliability issues.” 

Justice Ketanji Brown Jackson said she is concerned about the precedent the Supreme Court would set by pre-empting a ruling from the D.C. Circuit. 

“Your argument is just boiling down to, ‘We think we have a meritorious claim, and we don’t want to have to follow the law while we’re challenging it,’” Jackson said. “I don’t understand why every single person who is challenging a rule doesn’t have that same set of circumstances.” 

Representing EPA, Deputy U.S. Solicitor General Malcolm Stewart argued that the court must consider harms that pausing the agency’s plan would have on downwind communities. 

“To stay the rule in its entirety based on some theoretical possibility that the contours of an 11-state rule might have been somewhat different if EPA had anticipated all the stays would be terribly unfair to the downwind states,” Stewart said. 

The agency has said the plan “will save thousands of lives and result in cleaner air and better health for millions of people living in downwind communities.” 

The final rule noted that ozone exposure increases risks of early death, exacerbates asthma symptoms and harms ecosystems. EPA also highlighted environmental justice benefits of ozone pollution reductions, noting that the agency’s impact analysis “found greater representation of minority populations in areas with poor air quality relative to the revised ozone standard than in the U.S. as a whole.” 

“The harms from a stay will flow to both the residents of downwind states who will experience health dangers and to downwind industry, which pays increased costs to compensate for upwind pollution and comply with the current, more stringent standard,” New York Deputy Solicitor General Judith Vale said, representing states in support of the rule. 

Vale argued that the costs of pausing the rule would be greater to downwind states than the costs the rule would impose on upwind states, noting that the rule requires “controls that downwind sources and many other sources across the country have already done, … like turning on pollution controls on power plants that are already installed.” 

Kavanaugh said both sides have shown evidence for harm, and therefore the “only other factor on which we can decide this under our traditional standard is likelihood of success on the merits.” 

When considering the merits, Kavanaugh said the court must evaluate whether EPA’s methodology was arbitrary and capricious. 

“One of the classic arbitrary and capricious conclusions is a failure to explain,” Kavanaugh said. “One of the complaints they have, which we have to evaluate, is whether they’re likely to succeed in saying that the rule was not adequately explained.”

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Nevada Draft Climate Plan Outlines GHG-reduction Priorities

Nevada has released a draft climate action plan that lays out steps the state can take quickly to move toward greenhouse gas reduction goals. 

The Nevada Division of Environmental Protection (NDEP) received a $3 million federal grant to develop the strategy, known as the Priority Climate Action Plan (PCAP). NDEP released a draft PCAP on Feb. 15; public comments will be accepted through Feb. 22. 

The plan lists a wide array of priority actions grouped into six focus areas. Among priority actions within the transportation focus area are incentives to electrify government and large commercial vehicle fleets, and rebates for the purchase of zero-emission vehicles (ZEVs) or electric bikes. 

Developing infrastructure for medium- and heavy-duty ZEVs is another priority, as is updating and expanding the state’s EV charging plan under the National Electric Vehicle Infrastructure (NEVI) program. 

Under the energy system focus area, the plan proposes incentives such as grants for developing clean energy hubs at former mining sites or brownfields. 

In addition to transportation and energy systems, the plan’s other four focus areas are buildings, industry, waste reduction, and landscape restoration and carbon sequestration. 

“The primary objective is to identify near-term, high-priority, implementation-ready measures to reduce GHG emissions,” the plan states. 

Implementation Grants

The PCAP is just the first phase of planning funded by the $3 million federal grant. The funding, from EPA’s Climate Pollution Reduction Grant (CPRG) program, will also cover NDEP’s development of a more in-depth Comprehensive Climate Action Plan (CCAP). 

In addition to money for planning, the CPRG will offer $4.6 billion for implementation of GHG-reduction measures included in a PCAP. States have a March 1 deadline for submitting a PCAP; applications for implementation grants are due April 1. 

Nevada set greenhouse gas reduction targets through Senate Bill 254 in 2019. The state is aiming for a 28% reduction in GHG emissions by 2025 relative to 2005 levels; a 45% reduction by 2030; and zero or near-zero emissions by 2050. 

But Nevada’s 2023 Greenhouse Gas Inventory has projected that GHG emissions will fall short of the reduction targets, with a 24.5% reduction in 2025 and a 27.8% reduction in 2030. 

The PCAP projects a 48.2% reduction in 2050. 

By implementing measures in the PCAP, Nevada could meet the 2025 and 2030 targets but would still come up short of the 2050 goal, the plan said. 

“Meeting 2050 goals will require additional measures, to be described in the CCAP,” the draft plan said. 

NDEP’s release of the draft PCAP comes after Gov. Joe Lombardo (R) last year ordered an overhaul of Nevada’s 2020 climate strategy to reflect his energy policies. Lombardo defeated the incumbent governor, Democrat Steve Sisolak, in the November 2022 election. (See New Governor Seeks Shift in Nevada Energy Policy.)  

Among policies in Lombardo’s March 2023 executive order was direction to meet the state’s energy demands with a diverse portfolio including solar, wind, geothermal, natural gas, storage and other resources.  

In contrast, the state’s 2020 Climate Strategy called for transitioning away from natural gas to meet the 2050 net-zero emissions goal. A link from NDEP’s website to the 2020 Climate Strategy now goes to a page reading “under construction.” 

NDEP applied for the CPRG planning grant in April 2023 and was awarded the funds in June. 

Neither the PCAP nor CCAP are intended to replace the 2020 Nevada Climate Strategy, an NDEP spokesperson told NetZero Insider. But the technical work and outreach for the two plans will help during revisions of the climate strategy. 

“Currently NDEP’s efforts are focused on the CPRG to ensure that Nevada is well positioned to apply for and secure the unprecedented level of federal funding for the implementation of emissions reduction projects in Nevada,” the spokesperson said in an email. 

Most-emitting Sectors

Nevada’s 2023 GHG inventory includes emissions data from 1990 through 2021 and projections through 2043. In 2021, the state emitted 37.2 million metric tons (MMT) of CO2 equivalent — 21% less than the peak of 47.1 MMT in 2005. 

The transportation sector was the leading contributor to GHG emissions in 2021, accounting for 34% percent of the total. Electricity generation and industry followed, with 30% and 16% of the total, respectively. 

Before 2015, electricity generation was the largest source of the state’s GHG emissions, with transportation in second place. 

The PCAP notes the strong prospects for clean energy projects in Nevada, where the technical potential is 6.27 billion MWh for commercial, residential and utility solar; 1.13 billion MWh for wind; and 54 million MWh for geothermal. 

“This dwarfs annual electricity consumption, which was approximately 39 million MWh in 2021,” the PCAP said. “Based on this, renewable electricity generated in Nevada could supply the state’s annual electricity needs multiple times over.” 

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NERC Committee Greenlights Shortened INSM Comments

NERC’s Standards Committee remains focused on meeting FERC’s deadlines, granting another waiver at its meeting Feb. 21 to authorize shortening the comment and ballot periods for the ERO’s proposed standard on internal network security monitoring (INSM). 

FERC directed NERC in January 2023 to submit standards requiring utilities to implement INSM at certain grid cyber systems (all high-impact systems, and medium-impact systems with external routable connectivity) by July 9, 2024. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.) The standard is being developed under Project 2023-03. 

The approaching deadline for Project 2023-03 was already on the committee’s radar. At its August meeting, members used their authority under NERC’s Standards Processes Manual to authorize shortening the initial formal comment and ballot period from the standard 45 days to as few as 30, and shortening additional comment periods to as few as 20 days. (See NERC Committee Agrees to Shortened Standard Comments.) 

Since the August meeting, the standards drafting team has posted its proposed standard, CIP-007-X (Cybersecurity – systems security management), for an initial comment and ballot period, which ran from Dec. 14 to Jan. 17. The standard failed to pass, reaching only a 15.42% segment-weighted approval. 

Alison Oswald, NERC’s manager of standards development, told the committee that as a result of feedback received during this comment period, the SDT decided that rather than updating an existing standard, it would be best to create a completely new standard, CIP-015-1. This move did not require the committee’s approval, but the team did seek authorization to further shorten additional comment and ballot periods for the standard — after the next one, already scheduled to begin Feb. 27 and last for 20 days — to as little as 10 days. 

While attendees of the meeting had no objection to the request itself, they did request that NERC staff clarify a point of possible confusion: As Oswald explained, the decision to draft a new standard meant the comment period would be listed in NERC’s balloting system as an initial ballot, rather than a follow-up round. After Oswald confirmed that staff would do their best to make sure industry understood the issue, members voted unanimously to approve the shortened comment period. 

Ironically, before the committee authorized shortening the comment period for 2023-03, Oswald had informed it that the initial ballot period for another project — Project 2022-03 (Energy assurance with energy-constrained resources) — had been inadvertently extended. 

The ballot pools for this project were to be opened Jan. 25, the day the comment period began, with ballot pools to be closed Feb. 23 and voting to conclude March 11. Oswald explained that the project’s administrator mistakenly opened the ballot pools three days early on Jan. 22. Because 50 pool members had already joined by the time the mistake was discovered, the team decided to leave the pool open and close it on the scheduled closing day, bringing the matter to the committee’s attention as required by the SPM. 

In a final standards action, the committee voted to approve changing the definition of “Automatic generation control” in NERC’s glossary to fix grammatical issues. The errors were discovered by the team for Project 2022-01 (Reporting ACE definition and associated terms), which was completed last week when NERC’s Board of Trustees approved its proposed glossary changes. 

As NERC Manager of Standards Development Jamie Calderon explained, the SPM states that correcting such errors does not require industry ballot if the Standards Committee agrees that the change “does not change the scope or intent of the associated reliability standard” or impact end users. Members again voted unanimously to approve the update. A NERC spokesperson confirmed that the newest definition will not require a separate vote by the board and will be submitted to FERC with the other definitions approved last week.

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Granholm Praises Impact of US Clean Energy Industrial Policy

Clean energy policies funded by the Inflation Reduction Act and Infrastructure Investment and Jobs Act (IIJA) have been key to the U.S. economy’s strong performance, Energy Secretary Jennifer Granholm said Feb. 21 at the National Press Club in D.C. 

The unemployment rate has been below 4% for the longest continuous stretch in 50 years, and among all advanced economies, the U.S. has seen the strongest recovery since the COVID-19 pandemic. 

“It is not luck,” Granholm said. “It’s the result of a focused strategic plan. The Biden administration is using a 21st-century industrial strategy to bring manufacturing back to America after years of offshoring, to lift bruised communities from their knees and to bring future-facing good jobs to workers.” 

Clean energy represents a $23 trillion global opportunity and effectively amounts to another industrial revolution, Granholm said.  

The past policies of free trade and trickle-down economics have led to millions of job losses as manufacturers were encouraged to move abroad, she said. 

“The loss of manufacturing jobs was the most sickening, despairing part of my eight years as governor of Michigan,” she added. 

In her first year as governor, home appliance manufacturer Electrolux was threatening to move a factory from Greenville, Mich., to Mexico, which threatened to crush the local economy as it employed 3,000 workers in a town with a population of 8,000. Granholm and her team offered generous incentives for it stay, but they could not compete with cheap labor in Juarez, Mexico. 

That situation was repeated 60,000 times over the course of the first part of this century, wreaking havoc on factory towns everywhere. 

“No matter how many incentives a state offers, no state has the resources to compete with the industrial policies of China, or the low wages in Mexico,” Granholm said. 

It was “like bringing a knife to a gun fight,” though Granholm’s administration was eventually able to convince a solar panel maker to open a plant that replaced some of the jobs lost to Electrolux’s move. But that manufacturer went bankrupt and shut its factory down as cheaper panels flooded the market, the product of China’s industrial policy. 

The energy secretary said Biden tasked his cabinet with developing a policy to bring jobs and businesses back to the U.S. through an industrial policy based in part on clean energy. 

“The president’s strategy is working, folks,” she said. “Did I mention 353,000 jobs last month? We now have the most significant clean energy and climate strategy in the nation’s history, arguably in the world.” 

That policy is based on four legs: making the U.S. the irresistible nation for investing in clean energy; ensuring that investments go to communities that have been left behind; strengthening America’s workforce so it has the skills to compete globally; and performing cutting-edge research and development. 

“DOE is now investing over $100 billion into clean energy demonstration and deployment through grants and loans and rebates and other public tools,” Granholm said. “We actually have 60 new programs under the [IIJA] and the Inflation Reduction Act. We’ve stood up new offices to focus on demonstration, clean energy supply chains, the electricity grid, community engagement and more.” 

China has its own policies, with 14 five-year plans focused on dominating supply chains and manufacturing in which the U.S. excelled, she said. 

“And as we saw with the solar company in Greenville, [China has] been successful,” Granholm said. “But we are fighting back. We’re being deliberate about building up these supply chains, both inside the U.S. and with our allies. We understand that energy is a national security imperative. We cannot depend upon countries that have orchestrated monopolies on key technologies, whose values we don’t share.” 

So far, those policies have produced more than 500 new or expanded manufacturing facilities in the clean energy space alone. 

“Five hundred communities that are seeing future-facing industries, hiring their people,” Granholm said. “We are bringing manufacturing home.” 

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US Needs More Renewables to Meet IRA Emissions Goal, Report Finds

A new report finds that U.S. zero-emission vehicle sales meet industry expectations set upon passage of the Inflation Reduction Act but utility-scale clean electricity expansion falls short. 

If the power sector continues to lag, it could jeopardize the greenhouse gas emissions reductions that were a central goal of the IRA, the authors write.  

The greatest barriers to clean energy deployment no longer are monetary, the authors say, but more intractable and longer-running issues such as siting and permitting delays, interconnection queue backlogs and supply chain shortages. 

“Clean Investment in 2023: Assessing Progress in Electricity and Transport” was released Feb. 21 by the Clean Investment Monitor (CIM), a joint project of Rhodium Group and MIT’s Center for Energy and Environmental Policy Research. 

CIM was launched in September 2023 to track public and private investment in technologies covered by the Infrastructure Investment and Jobs Act of 2021 and the IRA in 2022.  

The new report draws from the CIM database to compare 2022 and 2023 progress toward IIJA and IRA goals against the widely cited projections created by Energy Innovation, the REPEAT Project at Princeton University and Rhodium Group. 

All scenarios the three entities modeled showed a 37 to 42% GHG reduction by 2030 relative to 2005 levels, which fits with the IRA authors’ stated goal of a 40% reduction by 2030. 

CIM data suggest zero-emission vehicles (ZEVs), mostly battery electric models, accounted for 9.2% of U.S. light-duty vehicle sales in 2023; the three entities had predicted 8.1 to 9.4%. There were 1.43 million ZEVs sold in 2023 in the U.S.; in 2020, the Energy Information Administration had projected 580,000 ZEVs would be sold in 2023. 

The authors say the year-over-year growth in sales volume is likely to decline from the scorching 50% increase in 2023 but add that 50% sustained annual growth never was expected after the IRA’s passage and is not needed in order to meet the 40% GHG reduction. 

Expansion of clean energy generation, by contrast, is not happening fast enough, the authors say. The 32.3 GW of carbon-free generating capacity added to the U.S. grid was a new record and a 32% expansion over 2022, but it is not enough to meet the three entities’ projections of what is needed to achieve 40% GHG reduction by 2040.  

Those projections call for 60 to 127 GW in 2024 and 70 to 126 GW per year from 2025 to 2030. 

At the start of this year, 60 GW of new renewable capacity was projected to come online in 2024, but early-year projections of late-year start-up dates tend to be inaccurate, the authors state, and it’s likely that considerably less than 60 GW of capacity will be added this year. 

Addressing delays in siting, permitting, supplies and interconnection will be critical if the nation is to achieve the full potential of the IRA, the authors write. 

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Clean Energy Groups Seek FERC Re-evaluation of Automatic Penalties in MISO Queue

Multiple clean energy organizations have asked FERC to reconsider its approval of automatic penalties for withdrawing generation in MISO’s interconnection queue.  

The nonprofits, including the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance, said FERC “abandoned its own precedent without explanation” when it adopted MISO’s proposed escalating and automatic penalty fees on developers that withdraw projects from the queue (ER24-340).  

The penalty schedule was part of a package of stricter rules MISO proposed for its interconnection queue to pare down the number of speculative projects in its interconnection queue. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.) 

The penalty schedule will have a chilling effect on new generation entering the MISO queue, the groups argued, when FERC has emphasized that penalties shouldn’t discourage interconnection customers from lining up projects or withdrawing them in an orderly fashion. 

“MISO’s automatic withdrawal penalties will prevent projects that have yet to receive meaningful study results from entering the queue in the first place — precisely the ‘barrier’ the commission previously sought to avoid,” the nonprofits said in a Feb. 16 request for rehearing.  

The groups also said FERC’s buy-in to a “generalized harm” theory to remaining projects after project withdrawals and blanket penalty application is a departure from its emphasis on the “articulated linkage between the withdrawal and impact on other customers.” 

The organizations in particular argued against MISO levying penalties before interconnection customers have the chance to review MISO’s studies estimating the cost of interconnection. They said FERC used data from late-stage withdrawals when it approved the penalty, “ignoring contrary evidence that most early-stage withdrawals are driven by” the first study results interconnection customers receive from the RTO.  

They said it’s natural that many generation developers make the call to drop out at the queue’s first decision point — roughly 180 days into the interconnection queue — because at that point, MISO delivers the estimated totals of network upgrades. They said the decisions to stay or go are a reasonable response and not hallmarks of speculative projects. 

“Withdrawals at Decision Point I are not a result of a flaw in the interconnection process; rather, they are a result of the system working as it should — as the commission has previously held,” they said.  

The automatic penalty schedule allows MISO to recoup some of the first, $8,000/MW milestone fee developers pay to MISO while in the queue. The RTO can take 10% of the fee at the queue’s first decision point and 35% at the second decision point. Developers risk 75% of the amount by the time their project reaches the third and final phase of the queue and, finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement. MISO has said the forfeits will encourage interconnection customers to withdraw their projects as soon as they know they’re nonviable rather than linger in the queue.  

But the nonprofits said MISO’s “early-stage” penalties are not designed to detect whether a withdrawing project is affecting other interconnection customers and “serve as a purely punitive measure.” They said the RTO offered no compelling evidence showing automatic penalties will reduce late-stage dropouts.  

“In accepting the automatic withdrawal penalty provision, the commission does not explain how the provisions will address the early-stage problem of lack of information, or the problem of late-stage withdrawals and their associated harms,” they wrote.  

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FERC OKs Grain Belt Express Connection Agreement with MISO; Invenergy Displeased with 2030 Target

FERC on Feb. 16 approved a MISO transmission connection agreement for the $7 billion, 5-GW Grain Belt Express HVDC transmission line despite protests from developer Invenergy over a three-year construction lag contained in the contract (ER24-715). 

FERC disagreed with Invenergy Transmission that it should order MISO to insert a limited operation provision into the Grain Belt transmission connection agreement to allow it to begin partial operations in 2027. The commission said the agreement aligns with MISO’s current interconnection rules for merchant HVDC generation and approved it unexecuted. 

Invenergy argued the transmission connection agreement for Grain Belt is unfair because it doesn’t include an option for a limited operation of the line while Ameren Missouri completes network upgrades necessary for the merchant HVDC line. Invenergy said it began negotiations on the transmission connection agreement with a 2027 in-service date and MISO notified it in September that it must use a Dec. 1, 2030, in-service date.  

The transmission developer argued that other generators that gain injection rights on the MISO system are eligible for limited operations until they can be fully accommodated.  

However, FERC said Grain Belt’s agreement “appropriately reflects” the state of MISO rules and noted the agreement could be modified with a limited operation provision if a new rule is agreed on through the RTO’s stakeholder process. 

FERC said while it has allowed nonconforming interconnection agreements, they either must be necessary for reliability, raise a fresh legal issue or be required by “other unique factors.” 

“Grain Belt does not allege specific reliability concerns, novel legal issues, or other unique factors sufficient to show that the provision is necessary. Rather, Grain Belt states that, absent the nonconforming provision, there will be broad ‘adverse impacts on [Grain Belt] and on the customers that would otherwise benefit from the reliability, economic and public policy benefits that the GBX Line will provide,’” FERC wrote, adding that Invenergy’s arguments “merely highlight” the potential benefits — not essentials — that limited operation could provide.

Grain Belt is the first merchant HVDC customer to proceed through MISO’s interconnection queue, and Invenergy has said the status of the line means it and MISO inevitably will discover hiccups in the merchant HVDC interconnection queue rules and bring them forward for solutions in the stakeholder process.  

Invenergy said MISO told its employees it could initiate stakeholder discussions on adding limited operation options to merchant HVDC interconnections in the future but that the RTO didn’t commit to a timeline for introducing the issue in its stakeholder committees. 

“Under MISO’s timetable, by the time it starts stakeholder proceedings in a few years, develops a tariff proposal, and files it with and obtains commission approval, Grain Belt’s desired 2027 in-service date will have come and gone and MISO’s promise to look into this will not be a delay, but will amount to a denial of service,” Invenergy argued.  

The company said the RTO should have offered the same accommodations it would have for other interconnection customers, including limited operations provisions. It pointed out that both generation and merchant HVDC will transfer energy from their projects onto the grid and should be treated comparably under Order 2003.  

MISO responded that FERC’s Order 2003 was meant for generating facilities interconnection to the grid and doesn’t extend to merchant HVDC projects. It said Grain Belt was attempting to justify “nonconforming revisions with nonexisting policies.” 

Invenergy said that MISO’s rejection of a limited operations arrangement is wrong “given the urgent need for transmission in the U.S. and the harm to Grain Belt and MISO loads.” 

The transmission developer also claimed that “some amount of connection service and associated injection rights,” varying from 158 MW to 1,491 MW, could be supplied prior to the completion of Ameren’s system upgrades.  

Ameren Missouri maintained that it wouldn’t have given Grain Belt an impression of how much below the requested injection rights it could flow over its system because it’s up to MISO, not a transmission owner, to make that call. MISO said a possible amount of interim injection rights is irrelevant because Grain Belt didn’t meet FERC’s standard of addressing reliability concerns of unique operational issues.