[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.
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.
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.”
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.”
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.
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.”
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.
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 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.
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.
An uninhabited island on Maine’s central coast is the preferred site for a port to support the offshore wind farms state leaders hope will be built nearby.
Sears Island had emerged as the likely choice during a lengthy deliberation that included Eastport and Portland.
Gov. Janet Mills (D) announced Feb. 20 that it had in fact been chosen.
Consideration of Sears Island had been controversial all along, as it is a wooded nature preserve. After the decision was announced, island advocates confirmed the fight against development is far from over.
This has become a familiar role for them. Over the past few decades, they have fought proposals including a nuclear reactor, LNG terminal, coal-burning power plant and oil refinery. None ever reached construction.
The nearby region is not heavily industrialized, nor is it virgin wilderness. Tankers dock at a mainland oil terminal just a few hundred yards from northwest Sears Island.
And as Mills noted in her announcement, 330 acres of the 941-acre state-owned island are reserved for port development. Approximately 100 acres of that would be needed for fabrication, staging, assembly, maintenance and installation.
Nearby Mack Point, on the mainland, was evaluated along with Sears Island in a process that stretched more than two years. But Mack Point would have required dredging, adding to the cost of a project already expected to run in the $500 million range.
There are many more steps before the state can break ground on an offshore wind port, including independent state and federal reviews of the permit applications the Maine Department of Transportation plans to submit this year.
In consideration of the state’s large fishing industry, Mills in 2021 signed legislation banning new offshore wind construction in state waters. This puts the 3 GW of offshore energy generation capacity state leaders envision in federal waters too deep for fixed-bottom turbines. (See BOEM Designates Draft Wind Energy Area in Gulf of Maine.)
Floating turbines still are in research and development, including in Maine, where the state university has an ambitious program the state hopes to parlay into a lucrative new sector for its economy.
A good deepwater port would be a key part of Maine assuming a national or regional leadership status in floating wind.
Friends of Sears Island indicates it is not opposed to the drive for offshore wind or for a port. But Mack Point seems like a better site to them.
In a Facebook post Feb. 20 after Mills’ announcement, the organization said: “We are disappointed beyond words, of course, but there are many steps necessary before the port is built. The federal, state and local permitting process is onerous, and multiple challenges can be anticipated.”
Others applauded Mills’ decision, including labor and environmental groups eager for the anticipated economic and environmental benefits of offshore wind development.
Maine completed its Offshore Wind Roadmap a year ago. (See Maine Finalizes Offshore Wind Roadmap.) The state currently is awaiting federal approval to lease a site in the Gulf of Maine where it can tether 10 to 12 floating turbines as a test project.
State leaders hope placing the nation’s first floating research array off Maine’s coast will further boost the small state’s profile as the floating wind expands in the United States.
AUSTIN, Texas — Infocast offered attendees to its annual ERCOT Market Summit on Feb. 13-15 an “unparalleled deep dive” into impending changes still facing the Texas market and how they affect it.
Policymakers joined together with utility, renewable and trading executives to explore ERCOT’s future and examine the effects on resource adequacy, power prices and how to best meet the shifting needs of commercial, industrial and retail customers.
Coming as it did during the three-year anniversary of the 2021 winter storm that shut down thermal plants and natural gas facilities, leading to more than 20 GW of load shed and dayslong outages that devasted the state, speakers did not need much prodding to be reminded of what happened back then.
State Sen. Charles Schwertner (R), a leading voice on market design issues as chair of the powerful Senate Business and Commerce Committee that oversees electric market policies, said the Legislature’s work is not yet done.
“We have a responsibility to continuously assess the durability of the grid and potential deficiencies — the continual demands of our growing state — and update our policies to ensure our system adapts to ever changing conditions,” he said.
Schwertner cited recent comments from Texas Gov. Greg Abbott (R) that the state will need to grow its power supply by 15% a year to keep up with rising demand from industry and residential consumers.
“That’s a big number, 15%, and one that was not even considered a year ago,” he said. “Legislators must keep this in mind next session [in 2025] and be prepared to continue our work on powering Texas. We can confidently meet the projected demands of the state when we take an all-the-above approach to building our power portfolio.”
Much of the focus will be on resource adequacy and ERCOT’s potential movement away from market solutions to capacity shortfalls. A panel debating market design principles was asked whether the current design is sending the proper signals or whether investors remain concerned about regulatory uncertainty.
“Yes, all of the above,” responded Emily Jolly, associate general counsel for the Lower Colorado River Authority. “Fundamentally, I think there is a dispute about whether we do have a resource adequacy problem in ERCOT … and looking at the indicators of the viability of the forward market today and the amount of volatility that we’re seeing. But from our perspective, no question it’s a resource adequacy concern driven by market fundamentals that do not incentivize the types and quantities of generation that are needed to support the growth in Texas.”
“I completely agree with everything you just said,” R Street Institute’s Beth Garza told Jolly. “I think it’s relatively indisputable that the market is really not sending the price signals for resource adequacy.”
Garza, who was ERCOT’s market monitor until 2020, said the inaccurate price signals are the reason lawmakers created — and voters approved — the $10 billion Texas Energy Fund to incent more dispatchable generation, primarily gas-fired, and that state regulators and ERCOT are working on a performance credit mechanism (PCM) to restructure the current energy-only market. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)
“The question for us today is whether those steps are enough, whether the Texas Energy Fund is actually going to incentivize the kind of dispatchable generation that Texas needs,” Garza said, “whether the performance credit mechanism is going to incentivize the kind of reliability that ERCOT needs, and whether it’s going to provide the necessary funding for generators to conduct the kind of maintenances that are required to be able to provide energy during weather emergencies.”
E3’s Olson Defends PCM
Arne Olson, a senior partner at Energy and Environmental Economics (E3), found himself defending the firm’s PCM proposal from his fellow panelists.
The PCM is a market tool that would retroactively award incentive payments to dispatchable generation that meets performance criteria during the tightest grid periods. ERCOT and the Independent Market Monitor plan to produce a cost-benefit analysis on the PCM before next year’s legislative session. The mechanism had an early price tag of $500 million, but legislation last year set a $1 billion cap.
The cap “could limit its ability to perform the intended function, which is to stabilize revenues, particularly during a calm year. … That’s when you see the highest payments,” Olson said. “If the payments are lower than what it was, then the revenues are stabilized less. You have less market entry, and you have less reliability.”
“We all want reliability; we all want to improve sending the signals to resources; but we also want to balance the reliability benefit with the costs,” Shell Energy’s Resmi Surendran said. “The guardrail was put in based on a lot of debate and discussion … to say that annual net cost of PCM should not be more than $1 billion minus any of the benefits that are added to grid solutions.”
“One of the concerns I’ve had about some of the PCM is the interplay with the energy-only market. We don’t want to have 60% of the revenues coming out of PCM and 40% coming out of energy and ancillary services. That’s not a sustainable market,” Engie North America’s Bob Helton said. “So, as we design this, we’ve got to ensure that the PCM is the icing on the cake, and it is leveling out those revenues over a longer period of time and you save on investment. The rest gives you the flexibility and what types of generation you need.”
Helton said another of his concerns is dependent on the penalties for nonperformance during critical scarcity hours.
“You could create a situation where you overbuild the system and increase the cost of that just due to administrative penalties and not just because of some reliability issues,” he said.
Olson reminded the panel that the PCM’s primary purpose is revenue stability.
“It’s meant to address the boom-bust cycle, so when there’s a couple of blowout years, we’ll measure investments,” he said. If the “system is overbuilt and nothing happens for 10 years — the margins are low — then people start to exit the market. … It’s a residual market. It’s going to be based on the net cost of capacity, not zero cost, and so if someone has a blowout year, the PCM payments are going to be low. When it’s a calm year, that’s when the PCM payments will be higher.
“That’s how it increases revenue stability year over year with dispatchable generators and as a result of increased revenue stability. Carrying the cost of financing those resources should go down,” he added.
Noting other markets will continue to have boom-bust cycles, Jupiter Power’s Caitlin Smith said, “You can’t have one market that is completely stable and the inputs and outputs are boom-bust. I think that’s just the nature of markets.”
“We’re all looking at the same thing, and that’s, how do you operate and incent investment in a zero-marginal cost world?” Helton said. “It’s not going to be just the PCM. The PCM is a bridge to help us get there. We’ve got a lot of sausage-making, and we don’t know how good this is going to be.”
AC Link to National Grid Unlikely
News broke during the summit’s second day that U.S. Reps. Greg Casar (D-Texas) and Alexandria Ocasio-Cortez (D-N.Y.) had filed the Connect the Grid Act, mandating interconnections between ERCOT and its neighboring grids.
The legislation would direct ERCOT to build between 2.6 and 4.3 GW of capacity with MISO, SPP and the Western Interconnection. It would also give FERC oversight over pricing and transmission planning in ERCOT, a concept long considered anathema by Texas lawmakers and the market’s participants.
“I think it’s been discussed many times that we don’t want good connections because we don’t want FERC coming and telling us how to manage things,” Schwertner said during his opening keynote. “I don’t think we could have passed [legislation] in Texas these last three years, ensuring as robust response to those weather events, if we had Mother Federal Government telling us what to do. So, no, I don’t think it’s going to happen. I don’t really know how much of a reliability improvement it would be, quite frankly.”
A day later, Schwertner was more direct: “Not going to happen!” he posted on X.
Texas does have several smaller DC ties with SPP and MISO. Pattern Energy’s Southern Spirit, a 400-mile, 345-kV DC link into the SERC Reliability region, gained regulatory approval in 2022 after seven years of review. Because no ERCOT electrons will be mingled with other grids, the project will not bring Texas under FERC jurisdiction. (See “SCT Proceeding Closed,” Texas Public Utility Commission Briefs: Sept. 29, 2022.)
“AC ties are never going to happen. Too hard, too expensive,” Garza said. “DC, on the other hand, we’re missing out on.”
“I think it’s an incredibly unlikely idea that will never come to fruition, if for no other reason than creating that level of AC inter-tie to [other regions] invites far more FERC oversight than ERCOT wants,” Jolly said.
Panelist: ‘Bigger, Faster, More Tx’
Matt Pawlowski, vice president of development for NextEra Energy Transmission, had a quick response when asked how ERCOT can plan to ensure it has enough transmission to support oil and gas growth in the Permian Basin.
“Bigger, faster; make more transmission available. I mean, that’s the answer, right?” he said. “You’ve got to plan for it. It’s going to take seven or eight years to build transmission. This is an issue in every single region around the country. Plan for the build because the generation is coming; the transition is coming. You’ve got to get faster on planning; you’ve got to issue [notifications to construct] faster to build that transmission.”
Pawlowski’s mindset is driven in part by his experience lobbying politicians on Capitol Hill. He related an experience with three senior U.S. senators who were unable to distinguish between electric transmission and transmission systems in vehicles.
“Most of the time, I used to get laughed out of the room. People say, ‘Oh, he’s talking about that stuff. It’s really hard. It’s really expensive. We don’t need it anymore; everything’s fine,’” he said. “Now, all the questions that I hear is, ‘Can you do it faster, better, bigger?’
“I think it speaks to all the changes that are going on,” Pawlowski added. “There’s a lot of policy changes, a lot of things that we need to do, but you know, transmission is really at the forefront of what we’re hearing from our customers, from our regulators, from policymakers, from everybody all around. So, it’s an exciting time to be in the transmission space.”
