FERC on Dec. 29 rejected Duke Energy’s proposal to update the transmission planning process for its utilities in the Carolinas without prejudice, meaning the utility could file a similar proposal addressing the commission’s concerns (ER24-314).
Duke Energy Carolinas and Duke Energy Progress participate in the North Carolina Transmission Planning Collaborative (NCTPC), which identifies transmission upgrades needed to maintain new reliability and integrate new generation and load onto their systems in both North and South Carolina. It produces annual local transmission plans by studying the system’s reliability, economic and public policy needs.
In recent years, coal retirements, compliance with state and federal laws, and continued economic development have strained the current NCTPC process, Duke told FERC. About 8,400 MW of coal resources are planned to retire, and Duke’s integrated resource plans in both states call for 5,400 MW of new generation to replace that by 2030.
To ensure the replacements are available in time to maintain reliability, the Duke companies asked FERC to approve changes to their Joint Open Access Transmission Tariff that included setting up a new “Multi-Value Strategic Transmission Projects” class of lines, as well as increased transparency and coordination for NCTPC stakeholders. They also proposed changing the NCTPC’s name to the Carolinas Transmission Planning Collaborative (CTPC).
Duke proposed a threshold for projects to qualify in the new transmission planning process of $5 million, which it said would ensure all major transmission lines are covered.
“We reject Duke’s proposed Joint OATT revisions without prejudice to Duke refiling without the proposed $5 million estimated cost threshold,” FERC said. “We find that Duke’s proposal to implement a $5 million estimated cost threshold that must be met for any local transmission project to be planned through the CTPC process is not consistent with Order No. 890.”
While FERC has granted an exemption to asset-management projects and activities that do not expand the grid from Order 890, it has not exempted transmission projects and activities that expand the grid but fall below a cost threshold.
Besides the $5 million limit running afoul of that precedent, however, FERC said the rest of Duke’s proposal appears to be just and reasonable and otherwise consistent with the 2007 order, which governs transmission providers’ planning processes. The commission disagreed with arguments that Duke’s proposal to keep using its existing cost allocation method for the new Multi-Value lines and public policy projects would violate Order 890. Duke did not propose revising its default cost allocation, which means the Multi-Value projects would be recovered under the cost allocation policies in the tariff, satisfying Order 890’s requirements, the commission said.
The proposed CTPC process would also satisfy Order 890’s transparency principle because it would continue to disclose criteria, assumptions and data used in the planning process to interested stakeholders, FERC said.
Several parties opposed Duke’s proposal to recover the cost of the Multi-Value projects under its formula rate, but the commission determined it did not propose any changes to cost allocation at all, making that beyond the scope of the proceeding. Even if it was within the scope, FERC said it was not convinced it should depart from its own longstanding policy of rolling into transmission rates the cost of networked transmission facilities like the ones that would be planned under the CTPC.
FERC found concerns about the proportionality of benefits of the Multi-Value lines to be speculative and said protesters failed to make their case that such lines would benefit generation developers by having interconnection costs covered in transmission planning.
“Even if Duke’s revisions were to result in identification of network upgrades through the transmission planning process that otherwise would have been identified through the interconnection process, the cost of interconnection process-identified network upgrades are ultimately credited back to interconnection customers at transmission customers’ expense,” FERC said.
Commissioner Mark Christie filed a concurrence to the order saying that if Duke refiles the proposal to address FERC’s concerns, the record would benefit from the views of the North Carolina Utilities Commission and the Public Service Commission of South Carolina.
“I believe the record would also benefit from information they could provide as to the authority of the NCUC and PSCSC to approve integrated resource plans that include local transmission construction plans, as well as their authority to approve or disapprove permits to construct individual local transmission projects, such as through a certificate of public convenience and necessity process,” Christie said.
New York is moving to limit use of sulfur hexafluoride (SF6) in electrical power and distribution equipment and to reduce leakage of the most potent greenhouse gas.
The draft regulations produced by the state Department of Conservation include a phaseout of new SF6 installations, limits on emissions and multiple reporting requirements.
The Dec. 28 announcement included a similar set of draft regulations on hydrofluorocarbons, commonly used in refrigeration and cooling equipment. HFCs also are potent greenhouse gases though less so than SF6, which is used primarily to insulate electrical equipment.
The draft regulations are part of New York’s continuing effort to reduce greenhouse gas emissions. The Climate Leadership and Community Protection Act of 2019 mandates the state drop to 60% of 1990 levels by 2030 and 15% by 2050.
New York’s most recent GHG emissions report calculates total emissions statewide at 368 million metric tons of carbon dioxide equivalent in 2021. The great bulk of that was carbon dioxide (211 mmt) and methane (131 mmt). HFCs were a distant third, at 22 mmt.
Total emissions of SF6 were reported at just 0.15 mmt, but the impact is much greater than the number suggests.
SF6 has the highest global warming potential among the seven greenhouse gases subject to CLCPA regulations — as much as 25,000 times greater than carbon dioxide, depending on the timeframe used for calculations. It is an extremely stable chemical, persisting in the atmosphere for millennia once released.
Proposed Rules
The draft regulations would apply to anyone who owns, installs or uses gas-insulated equipment (GIE) that uses SF6 or substitutes as an insulating medium.
The phaseout gradually would bar acquisition of SF6 GIE for use in New York state, with a few exceptions for reasons such as compatibility or availability of non-SF6 alternatives.
It would take effect on Jan. 1 of various years, depending on the size of the equipment:
2026 for above-ground GIE with voltage capacity less than 38 kV; below-ground GIE with less than 38-kV capacity and a short-circuit current rating of less than 25 kA; or any GIE rated 38 to 145 kV and less than 63 kA;
2027 for any GIE rated 145 to 245 kV and less than 63 kA;
2028 for above-ground GIE rated at 38 kV; or any GIE rated 38 to 145 kV and greater than 63 kA;
2031 for below-ground GIE rated lower than 38 kV and greater than 25 kA; or any GIE rated 145 to 245 kV and greater than 63 kA;
2033 for any GIE rated higher than 245 kV.
Replacement parts would not be subject to the phaseout.
The draft regulations also include:
Formulas to calculate emissions limits that would take effect Jan. 1, 2028.
A requirement to establish and maintain a detailed inventory of GIE devices and insulating gases, effective Jan. 1, 2025.
Mandatory emissions reporting starting in 2026 for any GIE owner with annual emissions exceeding 7,500 metric tons of CO2 equivalent.
A requirement to maintain five years of records and provide them to the state within 30 days of request.
Problem Recognized
The New York emissions report indicates that SF6 emissions have been declining in the state thanks to technological and economic changes — older equipment may contain greater quantities of the gas and be more prone to leaks.
However, the National Ocean and Atmospheric Administration’s Global Monitoring Laboratory has shown atmospheric concentrations steadily increasing over the past two decades.
The Environmental Protection Agency has been working to reduce emissions of SF6 in partnership with the U.S. electric power industry, which has been using the synthetic chemical in circuit breakers, gas-insulated substations and other switchgear since the 1950s.
California and Massachusetts have placed restrictions and requirements on use of SF6, and the Regional Greenhouse Gas Initiative is encouraging incremental actions toward early retirement and replacement of equipment containing SF6.
Prominent corporate members of the power industry have formed the SF6 & Alternatives Coalition to develop best practices and increase awareness of substitute gases with lower climate impacts than SF6.
In announcing the draft regulations, DEC Commissioner Basil Seggos said: “HFCs, SF6 and other greenhouse gases are accelerating the costly economic, public health and environmental impacts of climate change in New York state and across the globe. The draft regulations filed today help bring New York closer to realizing the Climate Act’s ambitious emission reduction requirements.”
The draft regulations will be published in the state register Jan. 10, opening a public comment period and setting the stage for a public hearing March 14.
The folks at the U.S. Department of Energy don’t take too many days off.
The day after Christmas, the department released a Notice of Proposed Rulemaking on the enforcement of the energy efficiency standards for manufactured housing that it released in May. Those final rules were met — as many of the energy efficiency rules from the Biden administration are — with industry saying they will be too expensive and climate advocates saying they are not rigorous enough.
The NOPR looks to require the home developers to follow enforcement rules already in place from their professional organizations and the Department of Housing and Urban Development. Extra documentation may be mandated if potential violations of the regulations are suspected or found.
Reviewing DOE’s record of action ― both hits and misses ― in 2023, the word that comes to mind is “relentless.” Energy Secretary Jennifer Granholm was ubiquitous, popping up at conferences, research or manufacturing facilities and other events with exuberance at the latest DOE announcements. Department emails flew into reporters’ inboxes multiple times per day, with more NOPRs, requests for information or announcements of new funding opportunities or awards, all aimed at distributing the billions in clean energy funding from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.
Keeping up has been daunting but extremely important because Granholm and company have become the leading edge of President Joe Biden’s drive to decarbonize the U.S. power system by 2035 and zero out greenhouse gas emissions economywide by 2050.
The goal, as Under Secretary of Infrastructure David Crane often says, is a U.S. energy transition that is led by the private sector but enabled and accelerated by the government.
Crane and other officials at the department are laser-focused on reshaping the U.S. energy landscape, and they know they may have only another year to score the early wins and build the momentum needed to make any potential Republican rollback unpopular and unlikely.
Clean Energy Manufacturing and Jobs
The most immediate and transformational effects of the IRA’s clean energy tax credits have been through the ongoing wave of announcements of new clean energy manufacturing facilities, from solar and wind to energy storage and electric vehicles. In an end-of-the-year press release, DOE noted it had invested $169 million to accelerate the manufacturing of electric heat pumps at 15 sites across the U.S. and another $390 million to build out wind, solar and EV supply chains.
The American Clean Power Association is tracking 113 clean energy projects totaling $408 billion in private investment. | American Clean Power Association
The federal spending has prompted growing amounts of private investment. Tracking clean energy investments since the passage of the IRA in August 2022, the American Clean Power (ACP) Association reports that $408 billion of private sector investments have been announced in 113 new or expanded manufacturing facilities, creating close to 42,000 manufacturing jobs.
Perhaps most significantly, the new investments and jobs are concentrated in the Southeast and Midwest, where Republican lawmakers who opposed the IIJA and IRA now are welcoming the new manufacturing projects.
The Hubs
Red states also received a significant share of awards from the IIJA’s funding for hydrogen and direct air capture (DAC).
The law’s $7 billion for regional hydrogen hubs sparked fierce competition, with DOE selecting seven hubs to begin negotiations for their share of the money. As set out in the law, the seven hubs announced in October were regionally and technologically diverse. Proposed hubs in California and Texas made the final cut, as did multistate collaborations in the Midwest (Illinois, Indiana and Michigan), the Mid-Atlantic (Delaware, New Jersey and Pennsylvania) and the Pacific Northwest (Montana, Oregon and Washington).
The Appalachian hub in Ohio, Pennsylvania and West Virginia is intended to produce hydrogen using natural gas with carbon capture, and a “Heartland” hub in Minnesota and the Dakotas plans to use a mix of renewables, natural gas and nuclear.
DOE also committed another $1 billion from the IIJA to help build out solid market demand for the clean hydrogen the hubs will produce.
The department announced the first two DAC hubs that will be designed, in Granholm’s words, to “suck decades of old carbon pollution straight out of the sky” to be permanently stored underground or put to industrial or agricultural uses.
The hubs in Texas and Louisiana will receive a total of $1.2 billion in IIJA dollars, and neither plan to use the captured carbon dioxide for enhanced oil recovery — that is, pumping CO2 into low-producing wells to increase their output. Two more hubs will be funded, but DOE has said it may wait on launching the second round to allow a wider range of DAC technologies and business models to be developed.
In another year-end announcement, EPA granted Louisiana primacy over the permitting of wells and CO2 sequestration projects.
Doubling down on DAC, DOE is investing $500 million in IIJA funds to support the buildout of CO2 pipelines and launched a Responsible Carbon Management Initiative to “encourage … the highest levels of safety, environmental stewardship, accountability, community engagement and societal benefits in carbon management projects.”
This initiative reflects the fine line DOE and the Biden administration are attempting to tread on DAC and clean hydrogen. DOE and others have framed these still-emerging technologies as critical to the administration’s climate goals, but environmental groups remain skeptical, seeing them as a hedge for the continued burning of fossil fuels.
Transmission
Like industry in general, DOE is aware that reaching Biden’s goal of decarbonizing the U.S. electric power system by 2035 will not be possible without a major expansion of both intra- and interregional transmission and major changes in the way those lines are planned and financed.
In the department’s first foray into transmission finance, it announced in October that it would sign on as an anchor off-taker for three interstate transmission lines, with a capacity of 3.5 GW. The total investment from the IIJA could be up to $1.3 billion.
The projects again are geographically diverse — in the Southwest, Mountain West and New England — but all would bring renewable energy to areas with high demand and a need for system reliability and resilience.
According to DOE, the projects for the first round of funding from the IIJA’s Transmission Facilitation Program were chosen based on analysis in the 2023 Transmission Needs Study, released along with the funding announcement. The long-awaited study provided regional breakdowns of existing transmission and the intra- and interregional HVDC lines needed to ensure reliability and build up capacity for the power transfers across regions.
Interregional transmission also got a boost in DOE’s Grid Resilience and Innovation Partnerships (GRIP) program, which awarded $3.46 billion from the IIJA to 58 projects across 44 states. While most of the GRIP projects will be intrastate, the five transmission lines in MISO and SPP’s joint targeted interconnection queue (JTIQ) portfolio got $464 million, the largest of the 58 awards announced.
MISO and SPP’s JTIQ portfolio of projects received $464 million in DOE’s GRIP program. | MISO and SPP
DOE’s final interregional transmission announcement of the year came Dec. 19, when the department’s Grid Deployment Office released final guidelines for the designation of National Interest Electric Transmission Corridors (NIETCs). The corridors are narrowly defined geographic areas where transmission is urgently needed to ensure power reliability and affordability.
Aimed at speeding up the often decade-long time frame for transmission planning and permitting, NIETC designation would have DOE provide funding for new lines in that area and FERC exercise its “backstop” permitting authority in the event a state denies a permit for a project or delays it for more than a year.
EV Chargers and Tax Credits
DOE also faced some substantial challenges in 2023, which may become more significant as Biden faces low approval ratings during his campaign for re-election.
Specifically, promised consumer savings from the IRA’s tax credits and rebates for EVs and energy efficient home upgrades have been slow to materialize.
With $5 billion in IIJA funds, the National Electric Vehicle Infrastructure (NEVI) program was aimed at relieving consumer concerns about charging EVs by building out a national network of 500,000 DC fast chargers on U.S. highways. But almost two years on, the first federally funded charging stations only recently opened in Ohio and New York.
Sen. Joe Manchin (D-W.Va.) has been a constant critic of the Treasury Department’s guidelines for the IRA’s EV tax credits. | Senate ENR Committee
The IRA’s tax credits for EVs have been a continuing flashpoint for the administration, with Sen. Joe Manchin (D-W.Va.) repeatedly slamming the Treasury Department for its interpretation of the law’s domestic content provisions, which he considered too lax. More than 40 models qualified for either the full $7,500 tax credit or half in 2023, but under the latest regulations released in December, any EV with batteries or battery components made in China will not qualify for the credit, cutting down the list of qualifying vehicles to just under 20 models.
The combination of range anxiety and fewer tax credits could put a further damper on automaker and consumer confidence in EVs. Sales, while still healthy, are not growing as fast as expected, and automakers have pulled back investments.
On the upside, 11 states have joined California in adopting the Advanced Clean Cars II rule, according to the Atlas EV Hub. The rule requires that all or a major percentage of new passenger cars for sale in the states be zero-emission vehicles by 2035.
Appliance Wars
The IRA’s $8.5 billion for rebates for home energy-efficiency upgrades have been another point of frustrated expectations. The money, for “whole-home” upgrades and rebates on individual appliances, has gone through a long rollout, with DOE issuing guidelines for states to apply for their share of the money in August — a full year after the law was passed.
The application process for the states to get their allocation of the funds is complicated. The rebates are targeted specifically at low-income households, which means states have to ensure their own processes for income verification meet the federal requirements. Some states will have to hire staff to administer the programs, and the local contractors who will be installing the new appliances and other efficiency upgrades will need extensive training in the new technologies.
In other words, the money will not be reaching consumers and lowering their energy bills this winter.
At the same time, DOE continues to update appliance and building energy efficiency standards, as required by the Energy Conservation and Production Act.
As of Dec. 29, when DOE issued final efficiency standards for residential refrigerators and freezers, the department released a total of 30 proposed or final energy efficiency standards in 2023. The refrigerator standards have the support of industry groups, such as the Association of Home Appliance Manufacturers, which said DOE had done a good job of balancing efficiency improvements with consumer choice.
But the department sparked a political firestorm in February when it released proposed regulations for improving the efficiency of both electric and natural gas stoves, limiting the electricity or natural gas they could use per year. Republican and some Democratic lawmakers railed against the rule, saying it effectively would ban natural gas stoves. At congressional hearings on the matter, some lawmakers compared how long it might take to boil water on electric versus natural gas stoves.
The congressional outcries built on debates at the state level, where the banning of natural gas hookups in new construction has become a flashpoint between local and state governments across the country. At least 24 states have passed laws that prohibit such bans, according to S&P Global.
Responding to the criticism, DOE released a statement “addressing misinformation” on the proposed regulations, which, it said, would not ban gas stoves and noting that the proposed standards would not go into effect until 2027.
Election Year
Politicizing consumer choice has become an effective argument for Republicans, who have leveraged it to win support even among some Democrats. A Save Our Gas Stoves Act (H.R. 1640), prohibiting DOE from enacting any energy efficiency standards on stoves, passed the House in June on a 249-181 vote but stalled out in the Senate.
Rep. Cathy McMorris Rodgers (R-Wash.) chairs the House Energy and Commerce Committee | House Energy and Commerce Committee
That bill began life in the House Energy and Commerce Committee, led by Rep. Cathy McMorris Rodgers (R-Wash.), one of the fiercest critics of both DOE and the Biden administration’s energy policies. Speaking on the House floor in support of the bill, McMorris Rodgers called DOE’s proposed regulations a “backdoor” effort by the department and “radical environmentalists” to “control the home appliance market.”
On the Senate Energy and Natural Resources Committee, Sen. John Barrasso (R-Wyo.), the committee’s ranking member, has been equally vitriolic, railing against any perceived misstep by DOE. In one of the year’s confrontations, Barrasso criticized Jigar Shah, director of the Loan Programs Office, for participating in industry events, including dinners, sponsored by the Cleantech Leaders Roundtable (CLR), a group Shah started in 2017.
Jigar Shah, director of DOE’s Loan Program’s Office | Senate ENR Committee
After Barrasso pushed him to stop attendance at CLR events, the notoriously quotable Shah defended his appearances at a wide range of industry conferences, saying, “I’m more accessible than a ham sandwich.”
But while Republicans continued to snipe at DOE, Congress mostly declined to act on a critical component of the energy transition: streamlining and accelerating permitting for transmission and the 2,000 GW of solar, wind and storage sitting in interconnection queues across the country.
The permitting provisions in the debt ceiling deal — the Fiscal Responsibility Act of 2023 — set new limits on environmental reviews under the National Environmental Policy Act and requires the reviews to be conducted under a lead agency to avoid repetition of efforts. But the deal left other core issues unresolved, such as if and how litigation of review decisions should be curtailed from the current six-year window.
The bill would require FERC to ensure that RTOs and ISOs plan and build the interregional transmission that will allow them to transfer 30% of their peak electrical loads to neighboring regions.
What is more likely is the upcoming presidential election will intensify Republican scrutiny of DOE, as well as accelerate the pace of the department’s efforts to distribute federal funds and issue regulations for a range of clean energy and energy efficiency initiatives.
A wild card in the upcoming election is Manchin, who has announced his intention to retire from the Senate and has said he is open to a third-party run. Jennifer Franks, a political consultant, has formed a long-shot political action committee supporting a bipartisan ticket of Sen. Mitt Romney (R-Utah) and Manchin, according to a report in the Deseret News.
Granholm is typically undeterred ― and determined. In a New Year’s Day post on X (formerly Twitter), she said, “We are charged up and ready for another job-creating, clean energy deploying and consumer-savings chapter of [Biden’s] Investing in America agenda.
“Buckle up because it’s going to be another historic year.”
When former Chief Operating Officer Rick Gonzales looks back on his more than two decades at NYISO, two events stand out among all else: the Northeast blackout in 2003 and Superstorm Sandy in 2012.
The 2003 blackout cut power to 55 million people in the U.S. and Canada and reduced the ISO’s load by 80%. Gonzales found himself continuously on the control room floor performing engineering support duties and working with the control room operators to restore power. The key was getting the ISO’s biggest line reconnected with PJM.
“I worked 24 hours straight that day,” Gonzales, who retired Dec. 31, said in an interview with RTO Insider. It was “probably the best day of my career, even though it’s probably the event that most people dread when they think about it.”
The blackout prompted Congress to enact the Energy Policy Act of 2005, which gave FERC authority to set mandatory reliability rules.
Gonzales remembered three long days of work following Superstorm Sandy, which severely impacted New York, particularly New York City, killing more than 50 people and destroying thousands of homes and an estimated 250,000 vehicles.
“[The storm] caused significant loss of generation and load, but we were able to keep the New York state grid up,” he said. “That was another really interesting event — really challenging event — but we came through it pretty well.”
Gonzales, who has been with NYISO since its inception in 1999, began working in the New York energy industry in 1987 when the ISO’s predecessor, the New York Power Pool, was responsible for grid operations. He was replaced as COO by Executive Vice President Emilie Nelson, effective Oct. 1. (See Emilie Nelson Named NYISO COO, Replacing Rick Gonzales.)
Reflecting on the early years at NYISO, he recalled “a lot of growing pains” and “regulatory uncertainty.”
“Getting [NYISO’s] markets up was a great thing from a reliability perspective” he said, since under NYPP, “we didn’t have the level of control of operating resources that we have today. … It really was a great step in the right direction and a major improvement to reliability.”
Gonzales recalled the debate over whether ISOs should be large, multistate regional transmission owners like PJM or ISO-NE. Gonzales said he and other staff concluded that “there really wasn’t a lot of cost savings” in being a large, multistate operator, since the generating fleets of New York’s neighbors were similar to its own at the time.
At one time, “being a single-state ISO was viewed as a negative, when compared to the broader multistate ISOs,” he said. Now, however, being a single-state entity “makes things easier because we only have one regulator and one set of policies to try and implement.”
“It’s been really intriguing to me over the years, how [being a single-state ISO] has turned from almost a negative into a positive attribute for the organized market in New York,” he added.
Asked for an insight he wanted to share with the next generation of leaders, Gonzales responded that “having a good technical foundation” and “being able to interact with regulators and stakeholders” are keys to success.
“So much of the energy industry is now charged with policy and regulatory directives,” he said. “So, it’s great to have a strong technical understanding of whether these new policies can work.”
NYISO’s Evolution
As the ISO has evolved from a basic grid operator responsible for keeping the lights on to a key player in New York’s clean energy shift it has been increasingly charged with providing unbiased technical information.
“I’ve seen a tremendous increase in the amount of information flowing out of NYISO to the state regulators primarily, but also to the Legislature,” he said, adding that ISO staff has been “doing a lot more outreach to these folks to provide them with unbiased information.”
Gonzales said he is optimistic about NYISO’s ability to adapt to the challenges of transitioning from fossil fuels to renewable energy resources.
From an engineering perspective, the biggest risk is “maintaining the expected level of reliability under this grid in transition,” he said.
He said New York should study how other regions transitioning away from fossil fuels, such as California, have faced reliability challenges.
“I think that regulator’s fear is that if reliability is compromised and people’s lights go out, and it can be linked in any way, shape, or form to the new set of resources or policy initiatives, then the public may not be supportive [of this transition] in the long term,” he said.
Gonzales said regulators “seem to understand that this [transition] is a difficult balance” and that the public broadly understands this challenge as well.
Gonzales also was asked about the role emerging clean energy resources, such as distributed energy resources (DERs) or dispatchable emissions-free resources (DEFRs), have in New York’s transition and the grid of the future.
Gonzales responded that these resources will be critical to achieving the goals of the state Climate Leadership and Community Protection Act (CLCPA), which calls for an 85% reduction in greenhouse gas emissions by 2050 and a 40% cut by 2030.
“The DEFR question is really interesting because it could be anything,” he said. “It could be modular nuclear; it could be some iron-based battery or other long-term battery. But it’s such an unknown that it is difficult to opine on.”
He added that the ISO is close to implementing the software necessary to integrate DERs into the ISO’s markets, which should help significantly with the state’s transition.
“Anything that’s dispatchable, however, is going to be a good thing for grid operations,” he added. “And even though [DEFRs] may be subject to operational limitations, if we can model it, then we can make it work.”
MISO juggled several projects over 2023 designed to fend off imminent reliability problems and will keep up the multitasking in 2024.
“I’m still concerned about pace. We still have a lot to do to stay ahead of our reliability issues,” MISO CEO John Bear said during MISO’s final board meeting of the year in December.
However, Bear said MISO accomplished much over 2023, including the largest MISO Transmission Expansion Plan (MTEP) it’s ever produced, a plan to install a sloped demand curve in the capacity auction, work on a future availability-based capacity accreditation for all resources and analyzing the system in preparation for a second cycle of long-range transmission projects.
“Thank you, thank you, stakeholders, for all the work you’ve done this year, and thank you in advance for all the work that you will do in 2024,” Bear said.
Outgoing Organization of MISO States President and Chair of the Michigan Public Service Commission Dan Scripps said MISO has come a long way in the short time since the 2022/23 capacity auction returned a regionwide shortfall in the Midwest.
“Sitting here today, I want to congratulate you on how far we’ve come since last spring,” he told members and directors.
Staff Issue Warnings: 1st Seasonal Auctions Measure up
Despite the grid operator raising alarms over future reliability, MISO’s first four-season capacity auction returned adequate supply, clearing capacity mostly between $2/MW-day and $15/MW-day. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)
MISO conducted the more complex seasonal auction a month later than usual in 2023, impeded by a FERC show-cause order because the RTO incorrectly calculated an unforced capacity-to-intermediate seasonal accredited capacity ratio that it uses to determine supply ahead of the auction.
“The implementation wasn’t completely smooth. There’s always a tradeoff between moving more deliberately and faster, so I’m not particularly worried about that,” MISO Independent Market Monitor David Patton reflected in June on MISO’s seasonal auction.
MISO Executive Director of Resource Planning Scott Wright said the 2022 capacity auction spurred members into adjusting plans that “changed the complexion of the footprint” in the 2023 auction and allowed all zones to meet their reserve targets.
MISO staff is clear the footprint’s current status as capacity-sufficient is temporary and that thermal plant retirements can be held off for only so long. They spent late spring repeating that the economical capacity prices belied MISO’s mounting resource adequacy risk.
Vice President of Operations Renuka Chatterjee said MISO has a five-year market redefinition plan focused on ensuring its markets can better anticipate growing load uncertainty and output variability.
“Getting to seasonal was so important,” Chatterjee said of MISO’s capacity auction, adding that it’s also valuable to accredit all resources based on when they’re likely to be available over a season.
Last month, MISO reported that over the last five years, its installed wind capacity has increased by 74%, while solar has increased by 1,261%. Combined, MISO’s wind and solar fleet is nearing 30 GW.
MISO’s annual resource adequacy survey in conjunction with the Organization of MISO States this year showed the potential for a 2.1-GW total shortage in the summer of the 2025/26 planning year that could escalate to a 9.5-GW shortfall by the 2028/29 planning year.
Queue Scrutiny
In spite of the RA survey results, the MISO footprint continues to sit on 50 GW of new generation projects that are cleared to connect to the system but are languishing unconstructed. The unrealized gigawatts have added more concern to MISO’s resource adequacy problems. (See “50 GW in Greenlit and Unfinished Projects Haven’t Budged,” MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries.)
“Once we get supply chain issues figured out, we’ve got good projects that will make reliability contributions. … But the timing is pretty unclear, when these technologies can be deployed at scale,” Wright told the Advisory Committee at its Sept. 13 meeting.
The Cardinal-Hickory Creek line under construction | ATC and ITC Midwest
Fresh Energy’s Mike Schowalter said MISO is on “the tip of the iceberg” in terms of renewable energy and intermittent output. He also predicted distributed energy resources are going to be “bigger than we appreciate.”
At the same meeting, Michigan Public Power Agency’s Tom Weeks said the threat a warming planet presents means MISO members must come up with answers quickly on how to reliably accomplish a decarbonized fleet. He said members of the Advisory Committee should devote meetings to discussing emerging issues.
At last count, MISO’s queue contains more than 1,300 mostly renewable energy projects at nearly 230 GW — or about double its footprint-wide load on a hot summer day. Most of the proposed projects in the study phase of MISO’s interconnection queue are delayed.
“I think looking into the future, the queue is the future. If you want to know what’s coming in 10-15 years, look at the queue,” Wisconsin Commissioner Tyler Huebner said at the September Advisory Committee meeting.
MISO, hoping to cut back on speculative projects in the queue, proposed to establish an annual megawatt cap on projects, enforce stricter proof of land use, enact automatic and escalating monetary penalties for withdrawals, and increase milestone fees for its generator interconnection queue. That filing is awaiting FERC’s approval, with many stakeholders saying there’s no proof a megawatt cap will speed up MISO’s study processing times. (See MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries.)
As the holidays came and went, MISO still hasn’t closed its window on accepting proposed generation projects for its 2023 interconnection queue cycle. It said it’s holding off on rounding up new projects until FERC renders a decision on the measures.
“You shouldn’t be in the queue if it’s not your intent to build as soon as you have a [generator interconnection agreement],” MISO’s Andy Witmeier said during the August Planning Advisory Committee meeting.
MISO expects members will add 369 GW of new, mostly renewable resources by 2042 and have retired about 103 GW of their existing fleets, bringing the RTO’s total installed capacity to 466 GW. However, only 202 GW of that capacity is assumed to be accredited; staff assumes a declining effective load-carrying capability for the renewable additions. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.) MISO today operates with about 194 GW in nameplate capacity.
MISO’s prediction of installed capacity in gigawatts by 2042, including new and retired resources based on its members’ plans | MISO
During MISO’s June Board Week, Illinois Commerce Commissioner Michael Carrigan thanked MISO for moving toward a sloped demand curve in its capacity auctions. He said then RTO “cannot ignore portions of the footprint that use different planning approaches,” referring to Illinois’ status as a retail choice state.
“We’ve been in market failure for 20 years because we have a demand curve that doesn’t produce any signals for developers,” Patton said of MISO’s existing vertical demand curve at the beginning of 2023.
MISO has said it will reveal line recommendations next year and has emphasized lines will be needed for reliability’s sake to support its members’ energy transition. The RTO is accepting transmission project suggestions from stakeholders.
During a Dec. 6 Advisory Committee meeting, ITC’s Brian Drumm said “rocket fuel” is being poured on the energy transition, requiring major transmission planning of MISO. Drumm told fellow members the “risks of falling behind are much greater” than taking a stab at new line recommendations.
In midyear, MISO proposed a 50/50 split on its third LRTP portfolio, where costs would be allocated 50% regionally and 50% to local zones where the projects are located. The new cost allocation design is tailored specifically to the upcoming transmission projects MISO will recommend for its South region. It’s unclear whether FERC will sanction a separate cost allocation for different LRTP portfolios. So far, Midwestern LRTP projects use a 100% postage stamp to load allocation.
MISO long has said allocation negotiations are a major challenge to raising new transmission towers.
“We can come up with projects, but the allocation is typically the most challenging part of addressing the needs of the fleet evolution,” Vice President of System Planning Aubrey Johnson told board members at a June 13 System Planning Committee meeting.
In June, Director of Expansion Planning Jeanna Furnish said MISO might consider stringing long-distance, high-voltage lines to allow transfers between load centers like the Twin Cities to St. Louis to Des Moines.
“Staying where we are is not possible. Staying where we are is fraught with [reliability] risks,” Senior Vice President of Planning and Operations Jennifer Curran said at a March board meeting.
“We’ve got 40 million people depending on us for their lives and livelihood, so we have to get this right in this transition,” Bear added.
Bear said the widespread winter storm in December 2022 was in fact a positive because it tested the system, control room and staff. He said it’s important for MISO to be able to test its limits.
“There’s a whole lot in front of us, next year, next year and probably the year after that,” Bear said. “Just in case we get complacent, there’s another extreme weather event every 18 months to keep us on our toes.”
SPP’s Markets+ senior leadership closed out 2023 by approving the day-ahead market’s proposed governing document, a significant milestone in the grid operator’s drive to file a tariff with FERC in early 2024.
The Interim Markets+ Independent Panel (IMIP), composed of three of SPP’s independent directors, signed off on the document during a Dec. 19 conference call.
The stakeholder-driven Markets+ Participants Executive Committee (MPEC) endorsed the governance structure earlier in December. However, the structure received only 73% of the favorable votes over concerns by independent stakeholders that weighted voting factors could lead to unintended consequences in their sector. (See SPP’s MPEC Approves Markets+ Governance Plan.)
The IMIP accepted a friendly amendment to defer consideration of the independents voting structure until a future meeting. SPP general counsel Paul Suskie said he will work with MPEC Chair Laura Trolese to set up more discussions before its Jan. 23-24 meeting in Westminster, Colo.
“We’re encouraging the MPEC to have additional conversations and a discussion before the meeting itself regarding those voting within the independent sector,” IMIP Chair Steve Wright said. (The IMIP is serving as an interim governance body until a MIP is agreed upon in a later phase of Markets+.)
Under the governance rules adopted by MPEC on Dec. 7, votes by the investor-owned utilities and public power member sectors will be weighted based on their load share. Voting among the independents will be structured to ensure that participants contributing generation to the market receive two-thirds of the sector vote, while those without generation receive one-third.
The Northwest and Intermountain Power Producers Coalition (NIPPC), representing independent generation developers and storage, power marketers and affiliated companies, was unsuccessful in seeking to continue the status quo of giving each independent member a single vote within the sector.
NIPPC’s executive director, Spencer Gray, reminded those on the call that the MPEC’s governance vote was on the attachment as a whole.
“I don’t want to guess how the rest of the sector who voted no would have voted if the issue were just narrowly on this part of the governance attachment,” he said. “I wouldn’t want an amendment to the motion and approval of that to constrain us to the degree we can’t address that connected issue to the intersector voting, but it’s not narrowly limited to what the weighting of the vote is. It’s a secondary important issue anticipating tensions in the future in the market.”
“All we’re doing is acknowledging more work needs to be done on this particular section,” the IMIP’s John Cupparo said. “That doesn’t preclude conversations on the rest of it, even with the approval.”
The approved language also spells out Markets+’s functions, including: the makeup and roles of SPP’s Board of Directors, permanent MIP, MPEC, Markets+ State Committee and other standing committees; the MIP election process; meeting policies; the voting process for market policies; and process for appealing decisions. It also covers the establishment of working groups and task forces, the role of SPP staff, and attendance and proxy voting policies.
The Markets+ Greenhouse Gas Task (GHG) Force reported progress in its effort to incorporate GHG emissions-related information in the market’s reporting, price formation, commitment and dispatch processes. The Public Generating Pool’s Mary Weincke, who chairs the task force, told the IMIP the group reviewed and updated its conceptual design and tariff language during two December meetings.
The task force, which next meets Jan. 3, has created an ad hoc group to start working on a concept for nonpricing programs, separate from the more important task of developing a pricing program solution.
In the quest to increase U.S. domestic production of critical minerals needed for clean energy technologies, there have been successes and setbacks, researchers said during a recent webinar.
One success is the Gibellini vanadium mine near Eureka, Nev., which will be the first primary vanadium mine in the country.
Nevada Vanadium Mining Corp.’s Gibellini mine received approval from the Bureau of Land Management in October, “which is huge,” said Taylor Quinn, a graduate student in the mineral and energy economics program at the Colorado School of Mines.
Quinn spoke during a critical minerals webinar hosted by the Western Interstate Energy Board (WIEB) on Dec. 13. She was joined by Ian Lange, director of the mineral and energy economics program.
Vanadium is used in long-duration energy storage systems, as well as in steel manufacturing and aerospace applications. The U.S. Geological Survey has deemed it a critical mineral.
The Gibellini project is expected to produce almost 10 million pounds of vanadium a year, enough to meet about 60% of U.S. demand.
Quinn also gave an example of a critical minerals setback: Rare Element Resources’ proposed Bear Lodge mine in Wyoming. The Bear Lodge site features high-grade deposits of rare earth elements that are important in green technologies such as electric vehicles, solar panels and wind turbines, the company said on its website.
The mining project was suspended in 2016 after more than $140 million was invested, Quinn said, due to the falling prices of rare earth elements and struggles with the permitting process.
Now, Rare Element Resources has revived the project with a new rare earth processing method. But the company still must navigate the permitting process, Quinn said.
“So while the Bear Lodge mine is not a failure by any means, it’s just an example to show you how long these processes can take and the setbacks that you can experience,” she said.
The federal government has created a streamlined permitting process for certain infrastructure projects through the FAST-41 initiative. The name is a reference to Title 41 of the Fixing America’s Surface Transportation Act of 2015.
Infrastructure projects may be eligible for the FAST-41 process if they’re in one of 18 designated sectors, which include renewable or conventional energy production, electricity transmission, carbon capture and mining.
Although offshore wind and solar projects have been accepted for FAST-41 streamlining, so far only one mining project has been covered, Quinn noted. In May, the federal Permitting Council announced FAST-41 coverage for the South32 Hermosa project, a proposed $1.7 billion zinc and manganese mining and processing operation near Tucson, Ariz.
Requested Research
The researchers’ work was funded by WIEB’s reserve expenditure plan, which is designed to reduce the organization’s long-term financial reserves to targeted levels through the funding of various projects. WIEB member states proposed the project.
The U.S. is now dependent on other countries to supply critical minerals needed for the clean energy transition, WIEB said in explaining the research. According to the International Energy Agency, clean energy technologies will account for 90% of global lithium demand over the next two decades, 60% of demand for nickel and cobalt, and 40% of demand for copper and rare earth elements.
“This project explores the potential for Western states and provinces to supply these critical minerals and materials domestically to support this transition,” WIEB said.
In addition to traditional mining techniques, such as open pit mines, Quinn also pointed to new technologies being explored.
One of those is recycling of tailings, which are materials such as ground rock left over after ore is processed. The tailings may contain significant amounts of high-grade minerals, especially at mines that were decommissioned long ago, she said.
In addition, the Department of Energy has been supporting efforts to extract critical minerals or rare earth elements from coal production waste, such as fly ash.
Recycling of minerals from used batteries is another option that’s expected to gain momentum as more batteries reach the end of their lives.
Sustainable Mining
Meanwhile, sustainable mining practices are being adopted, Quinn said.
Caterpillar is developing battery-electric mining trucks and has entered into electrification agreements with mining companies including BHP, Freeport-McMoRan and Newmont Corp.
Nevada Vanadium Mining’s Gibellini mine will be powered by clean energy from solar panels and battery storage built at the site. Haul trucks and other mine equipment will be electric, according to BLM.
The storage system will include a vanadium flow battery — a technology that’s viewed as being relatively safe and having a long lifespan.
Interest in vanadium flow batteries is growing. In October 2022, the California Energy Commission approved a $31 million grant through its long-duration energy storage program for a project that includes vanadium flow batteries from Invinity Systems and zinc hybrid cathode batteries, paired with carport solar panels. (See California Energy Commission Grants Long-Duration Storage Project $31M.)
To qualify for the Inflation Reduction Act’s tax credit for clean hydrogen, a plant’s power will have to be new clean energy generated in the same region as the plant and, by 2028, be matched to demand hour-for-hour, according to proposed rules the Treasury Department and Internal Revenue Service released Dec. 22.
Those three “pillars” — additionality, deliverability and time matching — are at the core of Treasury’s Notice of Proposed Rulemaking, which details all the definitions and conditions hydrogen producers will have to meet to cash in on the IRA’s 45V production tax credit. Meeting all the proposed requirements in the NOPR could be worth $3/kg of clean hydrogen produced for 10 years from the date a new clean hydrogen plant goes online.
The 45V credit is technology agnostic but requires that a plant’s lifecycle greenhouse gas emissions — measured from “well to gate,” or up to the point of production — must be between .45 kilograms and 4 kg per kilogram of hydrogen. As with other IRA tax credits, the plant also must pay prevailing wages and participate in registered apprenticeship programs.
The base amount of the tax credit has four tiers, beginning at $0.60/kg for emission of less than .45 kg per kilogram of hydrogen, and bottoming out at $0.12/kg for emissions of 2.5 kg to 4 kg. Those rates then can be multiplied by five if the prevailing wage and apprenticeship requirements are met.
To qualify for the credits, the clean hydrogen must be produced in the United States or a U.S. territory.
The NOPR’s provisions on measuring a plant’s lifecycle emissions are where things get complicated, especially if a plant is using electricity off its local grid, which in most cases will include some power generated with higher-emitting fossil fuels. The electrolyzers that split hydrogen off water molecules to make green hydrogen are “very energy intensive,” according to a senior administration official, speaking at a prerelease press call Dec. 21.
“If you put a lot of energy into [making hydrogen], and you’re taking those resources off of powering homes and industry and buildings, then that power has to come from someplace, and if it’s being backed up with fossil fuel power, you’re adding to emissions.”
Treasury worked with the Department of Energy and EPA to develop a workable strategy for measuring lifecycle emissions, Developers or plant owners will be able to use DOE’s Greenhouse Gases, Regulated Emissions and Energy Use in Transportation (GREET) platform, a computer modeling tool, modified for hydrogen, according to the Treasury press release.
The new model and a user’s manual were scheduled to be publicly available Dec. 22.
Treasury, DOE and EPA officials at the prerelease briefing stressed that the rules being released are only proposals. The NOPR includes questions on issues that are still unresolved and need more input from stakeholders, they said.
The release Dec. 22 begins a 60-day comment period. A public hearing is scheduled for 10 a.m. EST March 25.
Energy Attribute Credits
Under the proposed rules, producers would use energy attribute credits (EACs) to demonstrate that they are, in fact, purchasing clean power based on the three criteria. The goal here is to provide rigorous standards for clean energy, while also allowing flexibility to account for emerging and evolving technologies.
In a DOE white paper also released Dec. 22, EACs are defined as “legal instruments that represent an exclusive claim to the attributes of a unit of energy. … In the case of electricity, EACs verify that a certain unit of electricity was generated by a specific entity and has specific associated attributes.”
EACs include renewable energy credits but are not limited to renewable generation.
For the EACs used for the 45V tax credits, the critical attributes include:
New clean energy is defined as any generation that went online within three years of the hydrogen plant going into operation. It could also include existing plants that expand capacity.
The proposed rule on deliverability would be based on the transmission regions identified in DOE’s recent National Transmission Needs Study. Because California, New York and Texas are self-contained transmission regions, Treasury may consider allowing clean power from an adjacent region to qualify.
Technology to provide hourly time matching is not yet widely available, so Treasury is proposing a transition period to allow annual matching until 2028, “when hourly tracking systems are expected to be more widely available.”
The exact transition timeline for time matching is one of the questions raised in the NOPR for additional stakeholder input.
Others include whether electricity from existing clean power projects or power plants that otherwise might be retired, such as nuclear plants, might be classified as new clean energy under certain conditions, and whether hydrogen produced from renewable natural gas or “fugitive methane” might qualify.
“We’re looking for pathways that will create the environmental integrity that we’re seeking, but that we believe will allow the nuclear industry to participate in the clean hydrogen economy,” the senior official said. “There are a series of potential pathways, including upgrading the facility, relicensing pathways that anticipate losses in generation as a result of retirements that could happen and including a carveout that would create a safe harbor essentially, where a percentage of their production can go into clean hydrogen.”
What They’re Saying
The U.S. has a well-established hydrogen industry, based on “gray” hydrogen technologies that use methane or natural gas (which is predominantly methane) as feedstocks. Speaking at the prerelease briefing, DOE Deputy Secretary David Turk noted that at present, clean hydrogen production in the U.S. is under 1 million metric tons (MMT) per year. President Biden’s goal is an industry that can produce 50 MMT per year by 2050.
“The 45V clean energy, hydrogen production tax credit is an important part of our strategy to unlock private investment across sectors and build a clean energy economy and tackle the climate crisis,” White House Senior Advisor John Podesta said at the briefing. “Clean hydrogen will be critical for reducing emissions from hard-to-decarbonize sectors like heavy industry and heavy transportation.”
“There is significant industry support for this [three-pillar] approach, as well as billions of dollars being invested in projects that have already announced they will follow this basic structure,” said Deputy Treasury Secretary Wally Adeyemo. “In addition to industry, investors have made it very clear that they’re looking to invest in projects that produce clean hydrogen, as well. … Allies and partners have already put similar structures for hydrogen in place, [so] having clear rules to ensure the U.S. develops a clean hydrogen industry will help drive innovation and demand for more advanced American-made electrolyzers.”
Backing up such statements, Treasury also has released additional statements from industry stakeholders voicing mostly positive support for the NOPR in general and the three pillars.
A recent letter from seven clean hydrogen and electrolyzer companies, including Air Products, Nordex Green Hydrogen and Electric Hydrogen, expressed “confidence that proposed 45V guidance requiring … additionality from day one, strong deliverability standards and a phase-in of hourly matching by 2028 … will support scaled industry growth.”
Laura L. Luce, CEO of Hy Stor Energy, a Mississippi-based green hydrogen producer, also supported the three pillars as critical foundation for long-term off-take agreements for clean hydrogen. The time-matching provisions in the NOPR “ensure the production of competitively priced hydrogen advanced organizations that are fully committed to the most timely and efficient industrial decarbonization,” Luce said.
But U.S. lawmakers are split on how strictly the three pillars should be formulated and enforced. Sen. Maria Cantwell (D-Wash.) led a group of 11 Democratic senators in a recent letter to Treasury, DOE and the White House, warning that overly strict definitions of clean hydrogen in the proposed rules might hamper industry growth.
The seven hydrogen hubs being funded with $7 billion from the Infrastructure Investment and Jobs Act include projects that would use natural gas or nuclear, which might not qualify for the tax credits.
In an Oct. 16 letter, Sen. Sheldon Whitehouse (D-R.I.) and seven other Democratic senators lobbied for a strict definition of clean hydrogen, excluding any produced with natural gas.
The lawmakers expressed grave concern about “the risk posed by weak standards for what constitutes clean hydrogen. Fundamentally, the 45V tax credit must not be applied to any projects that directly or indirectly increase power sector GHG emissions. Without safeguards, 45V risks creating a shell game in power markets, where existing clean generation gets nominally claimed by hydrogen electrolyzers, but the resulting gap in grid capacity is backfilled by fossil fuel generation.”
Disagreements over Hourly Matching
The proposal’s timeline for requiring hourly matching won praise from environmental organizations but drew fire from industry groups, including the American Council on Renewable Energy (ACORE), the American Clean Power Association and the Edison Electric Institute.
ACP CEO Jason Grumet called it a “a fatal – but fixable – flaw.”
“Imposing an hourly matching provision too early for first-wave green hydrogen projects will discourage a significant majority of clean power companies from investing in green hydrogen manufacturing and facilities,” he said. “ACP is encouraged to see that the Treasury Department has specifically requested comment on the adequacy of the transition schedule.”
Richard McMahon, EEI’s senior vice president for energy supply and finance, said the proposal lacked the flexibility to allow a rapid scale up to support a hydrogen economy.
The 2028 matching requirement “would undermine the commercial viability of this nascent domestic sector and severely limit the widespread adoption of hydrogen that is produced using grid-connected facilities,” he said. “As a result, the cost-reducing benefits for hydrogen included in the Inflation Reduction Act would be squandered, and an important new tool that electric companies and customers could be using to drive down carbon emissions and costs would be sidelined.”
But the Union of Concerned Scientists praised the proposal, calling it a “a strong foundation for accurately capturing the true climate impact of hydrogen production projects.”
“Rigorous guardrails are necessary to ensure the hydrogen tax credit incentivizes the scale-up of the right hydrogen, not just any hydrogen,” said Julie McNamara, senior energy analyst and deputy policy director of UCS’s Climate and Energy Program. “No less than whether or not hydrogen actually serves as a tool for climate progress hangs in the balance.”
The Natural Resources Defense Council also endorsed the hourly matching proposal.
“Anything less than the climate and consumer protections proposed today would be a giveaway to legacy energy companies eager to hijack hydrogen at the direct expense of the climate and consumers,” said Rachel Fakhry, NRDC’s policy director for emerging technologies. “Broad loopholes would be disastrous for the climate, kneecap our efforts to clean up the power grid, and harm the global potential of the U.S. clean hydrogen industry. Treasury must hold firm and finalize this strong guidance.”
WESTBOROUGH, Mass. — ISO-NE outlined key components of tariff changes it plans to make to comply with Order 2023 at the Dec. 21 Transmission Committee (TC) meeting, including cluster timelines and storage study assumptions.
Al McBride, director of transmission services and resource qualification, outlined the RTO’s proposed timeline for the cluster process, which would span 582 days before the initiation of a subsequent cluster. This is longer than the process proposed by FERC due to a 270-day cluster study period, 120 days longer than FERC’s proposal. To help reduce the total timeline, ISO-NE has cut the cluster restudy period to 90 days compared to its initial proposal of 150 days. (See ISO-NE Details Proposed Order 2023 Compliance.)
McBride said the RTO will allow letters of credit for the commercial readiness deposits, in response to a stakeholder request at the November TC meeting. ISO-NE is proposinga $5 million commercial readiness deposit for large generators seeking to enter the transitional cluster study, and a smaller fee for small generators.
Customers with a valid interconnection request as of May 1, 2024, will be able to proceed with a transition study or withdraw from the interconnection queue without penalties.
ISO-NE is also proposing to incorporate its existing cluster enabling transmission upgrade (CETU) process into the new interconnection procedures. ISO-NE can initiate CETUs for state resource procurements that seek interconnection in similar locations, as well as for withdrawn interconnection requests in the same part of the New England Control Area.
For ongoing affected system operator studies, which look at the effects of distributed generation projects on grid reliability, ISO-NE is proposing to allow transmission owners to continue studies if they are on track to be completed within 90 days of the start of the transitional cluster study.
McBride also outlined ISO-NE’s proposal for studying storage resources, which differs from the approach taken by Order 2023. The order would let interconnection customers choose the maximum system load at which batteries will be studied, while requiring control technologies to prevent batteries from charging when load exceeds these limits.
ISO-NE is proposing an approach that would avoid the need for control technologies, instead relying on energy market bidding to determine which batteries can charge. During the study process, the RTO is proposing to study batteries at an 18,000-MW “shoulder” net system load.
NEPOOL will turn its focus to stakeholder amendments to the RTO’s Order 2023 compliance proposal at its Jan. 4 meeting.
Longer-Term Transmission Planning
Brent Oberlin of ISO-NE introduced tariff changes associated with the second phase of ISO-NE’s Longer-Term Transmission Planning project. The project is aimed at enabling forward-looking transmission projects that can prepare the region for the load growth and changing resource profile associated with the clean energy transition. (See ISO-NE Updates Longer-Term Tx Planning Proposal.)
The new process will allow ISO-NE to issue a request for proposals (RFP) at the direction of the New England States Committee on Electricity (NESCOE) to address reliability needs identified in longer-term transmission studies.
To be selected in the RFP, bids will first be evaluated on whether they solve the identified reliability needs. ISO-NE will then consider a quantification of a project’s benefits relative to its total costs. The quantified benefits of a project must outweigh its costs over a 20-year period for the project to be eligible for selection, Oberlin said.
Once these thresholds are met, the cost-benefit ratio will be one of the aspects considered by ISO-NE when selecting the preferred solution, along with factors like operability and expansion capability.
Oberlin noted that NESCOE can cancel the project at any time throughout the process. This could introduce uncertainty for transmission developers, as the process would be contingent on the states agreeing on a cost allocation method.
David Burnham of Eversource said that some longer-term reliability concerns should be exempted from the RFP process and assigned to incumbent transmission owners. He said that an “overreliance on competitive RFPs” could incentivize greenfield projects over upgrades of existing infrastructure, reduce flexibility in the solutions selected and “increase risk of duplicative transmission investment,” such as overlap between the longer-term process and asset condition projects.
The proposed exemptions would be focused on “needs that can be addressed cost-effectively by upgrades to existing facilities or by maximizing use of existing properties/[rights of way].”
In Eversource’s proposal, ISO-NE could identify exemptions for “qualifying low-impact projects.” This definition would extend to upgrades or replacements of aging equipment, new infrastructure sited largely on existing rights of way and the deployment of grid-enhancing technologies.
ISO-NE initially floated the possibility that some reliability projects could be assigned to incumbent transmission owners but said at the November TC meeting that it would abandon this aspect of the proposal. The RTO said it received mixed feedback from stakeholders on assigning needs to incumbents and was concerned the development of these RFP exemptions would delay the overall longer-term transmission planning effort.
CAISO marked a key milestone in its Western expansion efforts Dec. 20 after FERC approved nearly every aspect of its proposed Extended Day-Ahead Market (EDAM).
The commission’s 181-page ruling rejected only one provision in the extensive proposal: a temporary measure designed to ensure interim compensation for any transmission providers that suffer financial losses during their transition into the new market (ER23-2686).
“CAISO’s proposal to improve the performance of its existing day-ahead market with new products, and to offer balancing authority areas outside CAISO’s current footprint the opportunity to participate in and benefit from a new day-ahead market, will create significant savings for consumers in Western states,” FERC Chair Willie Phillips wrote in a concurring opinion.
The ISO filed the EDAM proposal in August, not long after SPP began making significant inroads in the West with its own Markets+ day-ahead offering, setting the stage for a competition that could see the region divided into two different markets in the coming years. (See CAISO Files EDAM Proposal with FERC and Regulators Propose New Independent Western RTO.)
EDAM, an extension of CAISO’s real-time Western Energy Imbalance Market (WEIM), is the product of a nearly five-year initiative by the ISO and Western electricity sector stakeholders. The ISO paused the effort for a year after persistent heat waves in August and September 2020 caused rolling blackouts in California and strained grid conditions in the wider West. (See CAISO Promotes EDAM Effort in Forum.)
FERC’s relatively clean ruling signaled a solid endorsement of those efforts.
“Yesterday, we accepted CAISO’s extended day-ahead market (EDAM) proposal and the accompanying improvements to its day-ahead market,” FERC Commissioner Allison Clements posted on X (formerly known as Twitter) on Dec. 21. “I am excited by the continued developments in the West and am happy to support today’s [sic] order.”
CAISO CEO Elliot Mainzer said in a statement that he was “deeply appreciative of FERC’s decision and grateful for all the hard work that got us to this important milestone. As we turn the corner into 2024, we are excited to keep our momentum on implementation and to immediately begin working with stakeholders to address the one area FERC has asked for additional information for its consideration.”
Andrew Campbell, chair of the WEIM’s Governing Body, hailed the approval as “a landmark moment for cooperation in the West.”
“EDAM builds on the success of the WEIM real-time market by allowing participants to lower costs, reduce environmental impacts and improve reliability during the critical day-ahead planning period,” Campbell said. “With this market, the West will also be more resilient to unexpected changes in weather and other grid conditions.”
DAME Products
CAISO’s proposal consisted of two broad sections: one outlining a set of Day-Ahead Market Enhancements (DAME) intended to better align day-ahead market outcomes with real-time conditions, and the other comprising measures needed to implement the EDAM itself.
The DAME provisions create two new products designed to reduce “load imbalances” between the day-ahead and real-time markets. Resources with awards for either product will have to provide economic energy bids for the full range of their awards.
The first product category consists of “imbalance reserves,” a “flexible reserve product” the ISO will procure “up” or “down” in the day-ahead market to reduce uncertainty between the day-ahead and real-time net load forecasts and deal with real-time ramping needs not addressed by hourly day-ahead market schedules.
In approving the introduction of imbalance reserves, the commission said the product represents a “reasonable approach to help CAISO address new system needs brought on by the changing resource mix, such as large differences between CAISO’s day-ahead net load forecast and real-time system needs.” It said it was not persuaded by protests from NV Energy and the Western Power Trading Forum (WPTF) that imbalance reserves would be over-procured or “adversely affect the procurement of other ancillary services.”
The commission also set aside concerns by WPTF and others in agreeing with CAISO that imbalance reserves should be procured on a nodal — rather than zonal — basis to avoid the potential for the reserves to be undeliverable to transmission-constrained areas.
“Although the cost of procuring imbalance reserves nodally could be higher than if they were procured zonally, this does not render CAISO’s proposal to use nodal procurement unjust and unreasonable. Nodal procurement of imbalance reserves is intended to increase the probability that the capacity will be deliverable in real time,” FERC wrote.
The commission additionally approved CAISO’s proposed $55/MWh offer cap for imbalance reserves, saying it agreed with the ISO and its Department of Market Monitoring “that it is appropriate to impose market power mitigation on imbalance reserves offers to address market power concerns and ensure competitive market outcomes.”
The second new product category proposed under the DAME provisions is a “reliability capacity” product to be implemented into the ISO’s residual unit commitment process, a day-ahead process designed to ensure enough resources are committed to meet real-time needs. Under CAISO’s plan, reliability capacity will also be procured on an “up” or “down” basis “to meet positive or negative differences between cleared physical supply in [the ISO’s Integrated Forward Market] and the load forecast,” FERC explained.
“We find that the proposal will aid CAISO in reducing the need for out-of-market operator actions, thus improving the transparency of market prices,” the commission said in approving the product proposal, which elicited no protests.
Participation Model OK’d
FERC also largely approved the ISO’s participation model and implementation provisions for EDAM.
Just as with the WEIM, participation in the EDAM will occur at the balancing authority area level rather than at the level of individual utilities.
“Similar to participation in the WEIM, EDAM participation is voluntary, and an EDAM entity has flexibility in determining how much of its resource’s capacity it is willing to offer into the day-ahead market,” the commission wrote. “We agree with CAISO that WEIM entities (i.e., balancing authorities participating in the WEIM) are the appropriate participants in EDAM because in many cases, the EDAM entity will be the only or most significant transmission service provider in a BAA.”
The commission disagreed with the contention by Tri-State Generation and Transmission Association that roles within EDAM require further clarification.
“Although Tri-State argues that resources operating within an EDAM entity should not be forced to participate in EDAM, the commission’s obligation is to determine whether CAISO’s proposal is just and reasonable, and not whether it is superior to alternatives. Further, to the extent Tri-State’s arguments criticize the WEIM participation framework, we find that such arguments are outside the scope of the EDAM proposal,” FERC wrote.
The commission also deflected Bonneville Power Administration’s request that FERC emphasize the need for CAISO to develop a strategy for addressing market-to-market seams and acknowledge that entities such as BPA may require special provisions in agreement with the ISO with respect to EDAM and that such agreements should be required before the market can go live.
The commission said that request fell outside the scope of the proceeded and noted “that CAISO has agreed to work with Bonneville to revise the Coordinated Transmission Agreement as necessary to facilitate Bonneville’s participation in EDAM.”
The commission also approved EDAM provisions related to external resource participation; market design, market settlement and accounting, congestion and transfer revenue, market power mitigation, market monitoring, and governance. On the issue of governance, FERC dismissed concerns by BPA and Powerex regarding the lack of independence of the CAISO Board of Governors, the members of which are appointed by the governor of California. Powerex additionally contended that the ISO stakeholder process is biased in favor of California interests.
“We note that CAISO’s proposed EDAM governance structure is consistent with the existing WEIM governance, which the commission previously concluded is just and reasonable,” FERC wrote.
Access Charge Denied
The only portion of the EDAM proposal rejected by FERC was a provision that would have allowed transmission owners to recover shortfalls in short-term or non-firm transmission revenues that they could attribute to the transition of their assets into the market.
CAISO proposed the “EDAM access charge” as a temporary measure to smooth adoption of the day-ahead market. It would have allowed TOs to recover three different components of lost transmission revenues:
The difference between historical short-term revenues that would have been earned without joining EDAM and the actual amount earned;
Eligible network upgrade costs for projects that increase transfer capability between EDAM BAAs; and
Revenue shortfalls stemming from EDAM wheel-throughs in excess of an EDAM TO’s net transfers, represented by imports and exports.
But in proposing the provision, CAISO also said the access charge was “severable” from the rest of the EDAM plan, arguing that rejection of the mechanism should not hinder passage of the broader proposal.
FERC rejected the access charge despite a lack of protests from stakeholders, finding that CAISO had failed to justify its reason behind the three components. In her post on X, Clements emphasized the rejection was made “without prejudice.”
“While yesterday’s order rejects CAISO’s proposed EDAM access charge, it does so without prejudice to a future filing in which CAISO provides additional support for the proposal,” she wrote. “I encourage CAISO to work with its stakeholders to timely submit a new proposal with sufficient support for consideration by the commission.”
