Empire Wind 2 has dropped out of New York’s renewable energy pipeline, but its developers are looking for new ways to bring the proposed offshore wind farm to construction.
The Equinor/bp project would have a nameplate capacity of up to 1,260 MW as contracted. It is one of four New York projects — and several more in other Northeast states — with financial problems that reached crisis proportions in 2023.
It is the first to drop out in New York.
On Jan. 3, Equinor announced that it and bp had agreed with the New York State Energy Research and Development Authority to terminate the offshore renewable energy certificate (OREC) agreement for Empire Wind 2. The company said this will enable it to seek other offtake opportunities but did not clarify its plans further.
Equinor told NetZero Insider via email that the OREC agreement for Empire Wind 1 — the 816-MW first phase — remains in place. But the company would not say whether it plans to move forward with Empire Wind 1 as is, or would seek to rebid that project.
Nor would it say whether it plans to rebid Empire Wind 2 in New York or look to another state for a better deal.
However, it did express a firm desire to move forward with Empire Wind, a mature project in advanced stages of development. Federal regulators have granted the key final approval for both phases of Empire Wind, and state regulators have issued a key approval for the first phase.
New York and its neighbors along the coast — Massachusetts, Rhode Island, Connecticut and New Jersey — are at the forefront of establishing the American offshore wind industry. But all five states ran into major problems with their contracted projects starting in late 2022.
One after another, developers who had locked in their revenue but not their construction costs saw the finances for their projects become untenable amid decades-high inflation and interest rates.
Power purchase agreements for two projects in Massachusetts and one in Connecticut were canceled, putting all three projects in limbo. A two-phase project in New Jersey was canceled outright. A Rhode Island proposal was rejected as too expensive.
And developers of four projects that would feed the New York grid said they probably could not move forward to construction without more money from the state, which decided in October not to give them. (See NY Rejects Inflation Adjustment for Renewable Projects.)
Those four projects — Empire Wind 1 and 2; Beacon Wind, another Equinor/bp project; and Sunrise Wind, an Orsted/Eversource project — total 4,230 MW of capacity. They form an important part of the state’s strategy for making a clean energy transition and building a clean energy economy: Manufacturing development, port construction and workforce training are tied to the various proposals.
NYSERDA has been scrambling to not only salvage the four struggling offshore projects but add new projects to the pipeline.
In late October, it provisionally awarded contracts to three new projects totaling 4,032 MW: Attentive Energy One, Community Offshore Wind and Excelsior Wind. Importantly, that round of awards gave developers the option of including post-award/pre-construction inflation adjustments in their proposals.
Asked Wednesday for comment on Empire Wind 2, NYSERDA focused on positive details. “NYSERDA remains committed to advancing clean energy at the best value for New Yorkers, and we are encouraged that Equinor and bp continue to be committed to developing the offshore wind industry and New York’s green economy as they reset this project,” a spokesperson said.
In their official announcement Wednesday, Equinor and bp also struck an optimistic tone, continuing to emphasize the benefits Empire Wind could provide.
“The Empire Wind 2 decision provides the opportunity to reset and develop a stronger and more robust project going forward,” said Molly Morris, president of Equinor Renewables Americas. “We will continue to closely engage our many community partners across the state. As evidenced by the progress at the South Brooklyn Marine Terminal, our offshore wind activity is ready to generate union jobs and significant economic activity in New York.”
“Bp is supportive of NYSERDA’s leadership and commitment to offshore wind, which we believe is a critical part of New York state’s and America’s clean energy future,” said Joshua Weinstein, bp’s president of offshore wind Americas. “Offshore wind can deliver reliable renewable power as well as economic benefits to the state and its communities.”
ISO-NE enters 2024 with several major projects underway and is grappling with the sweeping changes and long-term uncertainty brought by the clean energy transition.
As the climate consequences of fossil fuel consumption accelerate, the RTO is tasked with balancing the at-times-competing objectives of grid reliability and decarbonization, all while keeping costs affordable for ratepayers. The proliferation of weather-dependent renewable resources accompanied by load growth from electrification poses novel challenges to the region.
Short on time and room for error, the region faces hard questions about the role of fossil fuels on the grid: Does a proposal to add natural gas capacity to Massachusetts have any chance to proceed amid the state’s intent to chart a future beyond gas? Will ratepayers be tasked with propping up an old LNG import terminal with unclear grid reliability benefits? Will a mix of intermittent renewables and clean dispatchable resources be able to scale up in time to replace retiring power plants?
For the states, 2024 also will bring major offshore wind solicitations coordinated between Massachusetts, Rhode Island and Connecticut. The Massachusetts legislature likely will try to piece together another wide-ranging climate bill aimed at speeding up the state’s clean energy transition.
Transmission will be another key area of work, as the Northeastern states look to increase collaboration to enable large-scale infrastructure investments.
As the clean energy transition heats up, there is no shortage of work left to do for New England’s policymakers, advocates, RTO officials and industry members.
Blowin’ in the Wind
Following a year characterized by high-profile offshore wind project cancellations, 2024 will be a crucial year offshore wind in the Northeast.
The success of the region’s nascent offshore wind industry will have both climate and reliability ramifications: ISO-NE resource adequacy assessments indicate offshore wind will be an essential resource for preventing energy shortfalls in the coming years. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) Offshore wind is also one of the key pieces of the states’ decarbonization ambitions — “an anchor for our state’s short-term and long-term success,” according to Massachusetts’ Gov. Maura Healey.
While the first wave of projects in the Northeast are set to power up in 2024, experts have expressed concern that the recent project cancellations threaten the states’ 2030 clean energy goals and that the region’s next round of projects may not come online until the 2030s because of the delays. (See Long-term Optimism Meets Short-term Concern at Offshore WINDPOWER 2023.)
To counteract the headwinds brought by high interest rates, inflation and supply chain constraints, Massachusetts, Rhode Island and Connecticut have agreed to coordinate their upcoming offshore wind solicitations to use their collective buying power. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)
Bids are due Jan. 31. In the meantime, lawmakers will hold their breath hoping for an abundance of affordable proposals.
Eyes on the Capacity Market
Major changes to ISO-NE’s forward capacity market are on the horizon in 2024. In early November, ISO-NE filed to delay forward capacity auction (FCA) 19 by a year to complete its ongoing resource capacity accreditation (RCA) project and consider structural changes to the capacity auction’s design. (See NEPOOL Votes to Delay FCA 19.)
The RCA project is set to shake up how the capacity market values the contributions of various resource types and could have significant implications on the capacity revenues available to both fossil and renewable generators.
Prior to a delay in the RCA project caused by a software error last year, early results (subject to change) indicated the accreditation changes would boost offshore wind and energy efficiency, while lowering the accreditation values of solar, storage and most fossil resources.
Gas resources that lack firm fuel commitments are likely to take an accreditation hit, incentivizing gas plants to firm up their fuel supplies through pipeline contracts or other supply arrangements. A similar phenomenon could occur for storage — short-duration batteries are likely to lose accreditation value, creating incentives for the development of longer-duration batteries. The RCA updates also likely will create an incentive for oil-burning resources to increase their on-site storage capabilities to improve their accreditation.
Grid officials and stakeholders also will spend a significant portion of the upcoming year considering whether to change the capacity market design from a forward-annual market to a prompt-seasonal market.
While auctions currently are held more than three years prior to their yearlong capacity commitment period (CCP), the prompt-seasonal format under consideration would cut the period between the auction and the CCP to just a few months, while breaking up the CCP into distinct seasons. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)
A draft report by Analysis Group recently recommended ISO-NE make the changes for FCA 19, saying a prompt-seasonal market would better prepare the region for the evolving resource and risk profile. ISO-NE plans to make its own recommendation in early 2024, after which stakeholder and grid officers would have to hammer out the specifics of the new capacity market.
Fossil Fuel Infrastructure, New and Old
The new year likely will bring some clarity to the ongoing saga of the Everett LNG import terminal, which has an uncertain future with the impending retirement of its main customer, the Mystic Generating Station, in the spring of 2024.
Evidence presented at a gas-electric reliability forum held in Maine in June demonstrated the importance of Everett to the gas system, Phillips and Robb said. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.) While ISO-NE’s winter reliability studies indicate the facility is not necessary to ensure the reliability of the grid in the coming decade, this conclusion may prove unfounded if the study assumptions around new resources and load growth are incorrect, they added.
At the same time, some ratepayer advocates (most vocally New Hampshire Consumer Advocate Don Kreis) argue the costs of Everett should not be forced on electric ratepayers with no evidence the facility provides any cost or reliability benefits to the grid.
Constellation Energy — owner of the Everett and Mystic facilities — has engaged in negotiations with Massachusetts gas utilities about keeping the facility open, but the talks have yet to produce an agreement, despite a Constellation representative’s testimony at the June meeting that “we’re just running out of time.”
Other aging fossil resources could face retirement in the coming years. In New Hampshire, the last remaining coal plant in New England submitted a dynamic delist bid and did not get a capacity supply obligation in FCA 17, which corresponds to the 2026-27 CCP.
The Merrimack Station, which has a capacity of 482 MW, has failed to complete a series of emissions tests over the past year, potentially indicating an additional air pollution risk for nearby residents and giving additional ammunition for climate activists calling for its immediate closure.
If the plant cannot fulfill its capacity obligation when called upon, it would face steep financial charges from ISO-NE.
Despite fossil retirements and increasing clean energy generation, the door is not closed on new fossil fuel infrastructure in New England. Enbridge is pursuing a project to significantly expand the capacity of its Algonquin pipeline into Massachusetts, and the company solicited requests for firm gas contracts this fall. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
In this open season request, Enbridge cited the grid’s continued reliance on natural gas, while noting that gas generators contract for only a small fraction of the gas needed to operate at full capacity. The pipeline company said the lack of firm gas contracts drives higher energy prices and hurts grid reliability during winter gas constrained periods.
The company’s case for more firm gas contracts could be bolstered by new resource accreditation rules that provide additional incentives for these contracts.
At the same time, the project is sure to face difficult climate and political headwinds. Massachusetts has strict sector-specific decarbonization targets, including a 70% reduction in power sector emissions by 2030 relative to 1990 levels. Furthermore, Gov. Healey has positioned herself as a climate champion, and climate and environmental justice activists have vowed to fight any gas expansion into the state.
Clean Energy Transmission
ISO-NE and the New England states are set to continue their work establishing a new long-term transmission planning process to facilitate the development and cost sharing of large-scale projects. The proposal would enable the states to direct ISO-NE to issue a request for proposals to address issues raised in longer-term studies.
Once ISO-NE has selected a solution, the states can choose to proceed with the project, either under a default regionalized cost allocation methodology or with an alternate methodology. The process is intended to enable a more proactive planning process that accounts for expected load growth and impending transmission constraints.
To advance interregional transmission, the six New England states, along with New York and New Jersey, launched a collaboration effort in June focused on enabling the interconnection of offshore wind. The announcement cited a pair of recent U.S. Department of Energy studies that demonstrated the need for new transmission capacity between the Northeast and Mid-Atlantic regions.
Meanwhile, ISO-NE, in coordination with NYISO and PJM, is contemplating whether to increase its single source contingency limit. The limit, which is set at 1,200 MW, applies to “all possible contingencies,” including new transmission infrastructure and generators, and is intended to prevent any outage from having an outsized impact on the system.
ISO-NE, NYISO and PJM are pursuing an interregional study looking into the justification of the current limit and potential upgrades, operational changes and associated costs associated with increasing the limit to 2,000 MW. Increasing the limit could enable larger interregional transmission lines and potentially facilitate the development of larger offshore wind projects.
But Wait, There’s More
Since helping elect a group of climate activists to lead ISO-NE’s Consumer Liaison Group at the end of 2022, members of grassroots climate and environmental justice groups have pushed the RTO to increase transparency and public engagement within its decision-making processes, board meetings and NEPOOL proceedings. (See Climate Activists Take Over Small Piece of ISO-NE.)
And 2024 could bring an increased focus on environmental justice at the RTO. At the request of five of the New England states, ISO-NE has agreed to include an environmental justice position in its 2024 budget. Activists have called on ISO-NE to hire someone with experience working closely with vulnerable communities.
ISO-NE and stakeholders also face a significant amount of work associated with FERC Order 2023 compliance, which is intended to reduce resource interconnection backlogs. To comply with the rule, the RTO is redrawing a large portion of its interconnection process. (See ISO-NE Details Order 2023 Tariff Changes.)
In Massachusetts, lawmakers are aiming to construct another omnibus climate bill building on major legislation passed in 2021 and 2022. A wide-ranging climate bill could have broad implications for climate and energy policy across the region. (See Checking in on Clean Energy at the Mass. Legislature.)
Topics the legislature has considered include the expansion of the state’s municipal gas infrastructure ban, the elimination of competitive residential electric suppliers in the state, and reforms to the state’s permitting and siting processes for clean energy.
A federal appeals court on Jan. 2 rejected Lincoln Electric System’s request to review a 2022 FERC decision turning down the Nebraska utility’s request to recover costs from its investment in a Wyoming generating facility.
The D.C. Circuit Court of Appeals said the commission correctly ruled the proposal as “unjust and unreasonable” to recover Lincoln Electric’s costs for Laramie River Station (LRS), which is located in a different SPP transmission pricing zone than the one assigned to the utility (22-1205).
At issue is Lincoln Electric’s joint ownership of LRS along with Basin Electric Power Cooperative, Tri-State Generation & Transmission Association and the Western Minnesota Municipal Power Agency/Missouri River Energy Services. The 1,700-MW, coal-fired facility is in eastern Wyoming and SPP’s Zone 19. Lincoln Electric is in Zone 16.
Lincoln Electric transferred operational control of its Nebraska facilities when it joined SPP in 2009. However, it has not done the same for the LRS facilities, choosing to recover those costs through rates charged to its Zone 16 customers.
In 2021, SPP filed tariff revisions at FERC modifying Lincoln Electric’s formula rate template to allow recovery from Zone 19 customers. The LRS owners and the zone’s transmission providers protested the filing, pointing out that SPP does not control Lincoln Electric’s LRS interest and that the proposal would illegitimately shift costs to Zone 19 customers.
“Lincoln’s proposal violates the cost-causation principle because Lincoln invested in LRS to serve its Zone 16 customers only,” Circuit Court Judge Karen LeCraft Henderson wrote. “That principle does not support Lincoln’s recovery of any of its LRS investment from Zone 19 customers, who did not cause Lincoln to incur these costs.”
Henderson noted that Basin Electric and Missouri River both transferred to SPP operational control of their LRS facilities.
“FERC reasonably found Lincoln’s proposal unjust and unreasonable, and it correctly interpreted its precedent and rejected Lincoln’s undue discrimination claim,” she said.
FERC approved transmission rate incentives for New York Transco’s Propel NY Energy project, but it ordered settlement proceedings on its proposed base return on equity of 10.7% (ER24-232).
Propel NY, a $2.7 billion 345-kV joint project between NY Transco and the New York Power Authority, was selected in NYISO’s public policy transmission needs (PPTN) assessment to deliver at least 3,000 MW from offshore wind farms near the Long Island coast. (See “Long Island PPTN,” NYISO Previews New York City Transmission Needs Assessment.)
New York Transco is owned by Consolidated Edison Transmission, Grid NY, Iberdrola USA Networks New York Transco and Central Hudson Electric Transmission. In October, the company asked FERC to include Propel NY in the ISO’s Rate Schedule 13 tariff, which governs how developers recover costs, and to allocate project costs based on a statewide volumetric load-ratio share.
The company also proposed a cost containment mechanism to essentially bar it from recovering the first 20% of any cost overruns.
FERC’s Dec. 26 order approved NY Transco’s request for 100% coverage for abandoned plant and construction work in progress (CWIP), and a 50-basis-point RTO participation adder.
But the commission reduced the ROE risk incentive to 75 basis points from 150 and suspended the proposed base ROE of 10.7% pending the settlement procedures, saying it could not resolve differing methodologies and proxy groups based on the record before it.
Complaints
The state Public Service Commission, the City of New York and Multiple Intervenors, representing large industrial, commercial and institutional energy consumers, opposed the proposed base ROE, cost containment, RTO participation adder and risk incentive.
They criticized the 10.7% ROE as inflated, and they argued that NY Transco failed to demonstrate any special project risks.
The commission’s ruling noted that it had not granted an ROE risk incentive greater than 50 basis points since its 2012 policy statement on incentives. But it acknowledged that Propel NY “involves new, high-voltage, completely underground and submarine electric transmission cables that will involve nearly 90 miles of excavation for underground cable in urban areas, underwater crossings and the need to directionally drill for 6,000 feet, as well as the construction of four transmission substations located in densely populated areas.”
“We find that the greater risks and challenges associated with those characteristics of the project warrant an increase in the level of ROE risk incentive compared to those earlier cases,” the commission said. “However, New York Transco has not justified an ROE risk incentive of 150 basis points, which we find would be excessive in these circumstances.”
Commissioner Mark Christie dissented, saying “the incentives granted in this order go beyond the commission’s practices and what should be accepted.”
Irrespective of the ultimate ROE calculation, Christie said, NY Transco’s requested incentives would be “egregiously unfair to New York consumers.”
He further contended that since Propel NY was selected through NYISO’s PPTN for its “relatively low procurement, permitting, and construction risks,” the claim for extensive incentives to mitigate these already-assessed risks should be rejected.
Avangrid has pulled the plug on its proposed $8.3 billion acquisition of PNM Resources, as final approval for the deal remains tied up at the New Mexico Supreme Court.
The court is considering the companies’ appeal of the New Mexico Public Regulation Commission’s decision in December 2021 to reject the acquisition. A green light from the PRC was the final regulatory approval needed.
While awaiting the court’s decision, the parties agreed several times to extend the deadline to complete the merger, including the most recent extension to Dec. 31. PNM was willing to extend the deadline an additional three months, but Avangrid said time was up.
“With the close of 2023, there is still no clear timing on the resolution of the court review of the New Mexico regulator’s denial of the merger nor any subsequent regulatory actions,” Avangrid said in a statement on Jan. 2. “Avangrid has terminated the merger agreement because all final regulatory approvals were not received by Dec. 31, 2023.”
PNM CEO Pat Vincent-Collawn said the company was “greatly disappointed” in Avangrid’s decision.
“We had been looking forward to providing customers with the immediate benefits in our agreement and also the longer-term benefits of being part of a larger-scale entity with ties to global innovation and experience in the clean energy transition,” she said.
PNM Resources is the parent company of Public Service Company of New Mexico, the state’s largest investor-owned public utility. The utility plans to transition its generation portfolio to 100% carbon‐free resources by 2040.
Avangrid said its decision doesn’t signal a loss of interest in New Mexico.
“We remain more than ever steadfast in our commitment to New Mexico in the development of wind and solar renewables, helping explore options in the new hydrogen economy and delivering on the partnership with the Navajo Nation to achieve its clean energy future,” Avangrid said in a statement.
Transaction Timeline
Avangrid and PNM announced their merger plans in 2020. The proposal was expected to bring more than $300 million in benefits to New Mexico, in the form of PNM customer rate credits, past-due bill forgiveness, low-income energy efficiency programs, new jobs, training programs and economic development funds.
But the PRC rejected the merger in December 2021, saying “the potential harms resulting from the proposed transaction outweigh its benefits.” The commission’s chair at the time, Stephen Fischmann, said Avangrid’s “demonstrated record of poor performance” in states such as Maine, Connecticut and New York could counteract any benefits PNM might see from the acquisition. (See NM Regulators Reject Avangrid-PNM Merger.)
The companies appealed the decision to the New Mexico Supreme Court the following month.
The merger seemed to be getting a fresh chance in 2023, when the PRC’s five elected commissioners were replaced with three commissioners appointed by the governor. (See New NM Commissioner Steps Down over Qualifications.)
The revamped PRC, along with Avangrid and PNM, asked the state Supreme Court in March to dismiss the previously filed appeal and send the matter back to the PRC for reconsideration. In a May decision, the court declined to do so.
The court held oral arguments in September on the appeal but has yet to issue a decision.
In its statement, Avangrid said it would continue to focus on growth opportunities, including $5 billion in capital projects under multiyear rate plans in New York and Maine and $2 billion in clean energy transmission projects in New York.
Avangrid is also a partner in Vineyard Wind 1, a utility-scale offshore wind project now under construction off the coast of Massachusetts.
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.”
