An energy market research group estimates that 159 GW of coal-fired power production will be online in the U.S. in 2026, down half from a peak of 318 GW in 2011.
By 2030, the Institute for Energy Economics and Financial Analysis report projects, the U.S. coal-fired fleet will be down to 116 GW, as gas, wind and solar power supplant it.
Fewer than 200 large units — those rated at 50 MW or more — now operating have not announced retirement dates, IEEFA said. The organization also noted an even steeper decline: Coal-fired plants now burn less than half as much coal and produce less than half as much electricity as they did in 2011.
Data were derived from internal IEEFA research, the U.S. Energy Information Administration, S&P Global and company reports.
IEEFA data analyst Seth Feaster, author of “U.S. on Track to Close Half of Coal Capacity by 2026,” said in a news release that the continuing trend does not bode well for the industry.
“This milestone is another clear sign of the ongoing and deep restructuring of the U.S. coal industry, as demand for the fuel continues to drop quickly,” he said. “It is likely to result in significant mine closures, layoffs, and falling tax and royalty payments in coal-producing states.”
IEEFA states that it takes a nonpartisan, evidence-based approach to its mission, which is to accelerate the transition to a diverse, sustainable and profitable energy economy. The 501(c)(3) nonprofit corporation lists multiple climate advocacy organizations among its financial supporters.
The Institute for Energy Economics and Financial Analysis projects a steady decline in U.S. coal-fired power generation. | Institute for Energy Economics and Financial Analysis
Its report speculates that coal power generation may decrease even more quickly than projected because of higher operation and maintenance costs for the remaining units, most of which went into service in the 1970s.
EPA in the last two months has taken multiple steps to tighten emissions regulators from coal-burning power plants; these are expected to prompt additional retirements. (See EPA Proposes Tougher MATS Regs on Coal Power Plants.)
The long-running effort to restrict and or reduce coal as a fuel in the U.S. has drawn criticism from the coal industry and its allies as a threat to energy security. But as federal and many state governments press to speed the transition from fossil fuels to emissions-free alternatives, some grid operators are voicing similar concerns. (See PJM Chief: Retirements Need to Slow down.)
The IEEFA report projects more than 80 GW of coal retirements from 2023 through 2030 and indicates 10.5 GW of the retired plants are expected to be converted to burn natural gas.
The pace of retirements will be steady over time, the report said, but not from year to year, as construction delays have ensued on renewable energy projects. For example, 11.8 GW of coal-fired capacity is currently announced for closure in 2023, less than 3 GW in 2024, 17 GW in 2025, roughly 10 GW in 2026 and 22 GW in 2027.
With the 2022 passage of the landmark Inflation Reduction Act, and its heavy emphasis on accelerating the energy transition and building a supply chain for it, the numbers could be in flux for a while.
The report noted that multiple factors in favor of coal in 2022 — soaring natural gas prices, high demand for power and the post-pandemic economic rebound — were counterbalanced by railroad delivery problems, a labor shortage and utility reluctance to increase coal use.
When coal’s use as a fuel for generating electricity in the U.S. peaked in 2011, it was responsible for 44% of power generation, EIA data cited in the report indicate. Based on current announcements and trends, coal’s power market share could decrease to 10% or less by 2030, IEEFA said.
PJM asked FERC on Tuesday to delay its next four Base Residual Auctions to give the RTO time to incorporate rule changes to address reliability concerns (ER23-1609).
The RTO initiated an accelerated stakeholder process in February to respond to concerns that the region could fall short of resources because of increased demand from electrification and a “timing mismatch” between plant retirements and new entries. It has promised to file the changes by Oct. 1. (See PJM Presents Alternative Capacity Auction Schedule.)
PJM’s Reliability Pricing Model (RPM) calls for the BRA to be held in May, three years prior to the start of the delivery year. But the schedule has been suspended since 2018 as the RTO has considered repeated changes to its capacity market rules.
The 2026/27 BRA currently is scheduled to open on June 14, 2023.
“While further delay of the upcoming RPM auctions is not ideal, continuing to conduct the auctions under the existing rules further exacerbates the challenge of procuring the necessary resources to facilitate the imminent energy transition while maintaining reliability,” PJM said. “In short, since the current tariff provisions … may be unjust and unreasonable and require change, it does not appear reasonable to continue to lock in resources on a forward basis to such provisions, particularly when they exacerbate the reliability issues that PJM has identified.”
The RTO requested to hold a BRA every six months through delivery year 2028/29.
PJM proposed the following “illustrative” BRA timeline, assuming the commission approves its proposed tariff revisions without material changes by Dec. 1, 2023:
2025/26: June 2024
2026/27: December 2024
2027/28: June 2025
2028/29: December 2025
The three-year forward schedule would resume for the 2029/30 BRA in May 2026.
PJM also proposed continuing its current practice of maintaining all third Incremental Auctions for each delivery year and canceling all IAs that fall within 10 months of the associated BRA.
“It is reasonable to cancel those Incremental Auctions that are within 10 months of a Base Residual Auction in these limited delivery years because there would be little, if any, need for such auctions under a compressed Base Residual Auction schedule, as very little time would pass between the Base Residual Auction and Incremental Auctions,” PJM said. “Moreover, market participants will always have the opportunity to buy back and offer additional capacity in the third Incremental Auction before the start of the delivery year under this proposal.”
Board’s Directive
The PJM Board of Managers called for action to enhance the modeling of winter risk and correlated outages; ensure sellers can reflect nonperformance risk in their offers; improve capacity accreditation for all resources; and ensure synchronization between capacity and fixed resource requirement rules. (See PJM Board Initiates Fast-track Process to Address Reliability.)
“That does not mean that the other topics PJM and stakeholders have been examining since April 2021 in the Resource Adequacy Senior Task Force may not be included in the upcoming enhancement filing,” the RTO told FERC.
Demand on the New England regional power system fell to its lowest level in over a quarter century Sunday, thanks to the holiday, mild weather and sunshine beating down on an ever-growing number of solar panels.
ISO-NE said Tuesday that demand on the grid was the lowest it had ever recorded since the RTO began operations in 1997.
The 6,814-MW demand between 2 and 3 p.m. shattered the previous record, 7,580 MW, set May 1, 2022.
Steven Gould, ISO-NE director of operations, said the new record was not surprising.
“The evolution of New England’s power system continues,” he said in a news release. “The previous record lasted less than a year, and this one likely won’t last long either. Each day, our system operators are seeing the clean energy transition play out in real time.”
The lowest demand for electricity during the week is typically on Sunday, and Easter historically sees even lower demand than the average Sunday. Warmer temperatures on this Easter reduced demand even further. Abundant sunshine clinched the record, as behind-the-meter rooftop solar panels across the RTO’s six-state region reached an estimated peak output of more than 4,500 MW.
ISO-NE said demand rose through the predawn hours of April 9 to peak at more than 10,000 MW just after sunrise, dropped below 7,000 MW to set the record in mid-afternoon, and rebounded quickly as the sun went lower in the sky.
Demand for the day peaked at more than 12,000 MW just after sunset. This created the so-called duck curve in the flow of electricity through the grid, in which demand bottoms out in mid-afternoon rather than the overnight hours, as it usually does. The graphic representation of this phenomenon on a line chart vaguely resembles the classic rubber duck bathtub toy.
And as Gould indicated, the duck population is growing.
ISO-NE did not record its first duck curve until April 21, 2018. Through Dec. 31, 2021, it recorded 34 more duck-curve days. Then, in calendar year 2022, it recorded 45 duck curve days.
Solar power potential is at its strongest in the spring, ISO-NE noted, and 27 of the duck curve days in 2022 were in March, April and May.
Summer 2022, with its midday air conditioning demands, saw very few ducks: two in September, one in June and none in July or August.
Late autumn and early winter also see fewer ducks, as solar power generation decreases before and after the winter solstice; ISO-NE recorded only two duck curves in January 2022 and just one in December 2022.
MISO says a recent rule change that places limits on MISO board members attending meetings hosted by state regulators is necessary, despite pushback from some commission members.
The Board of Directors voted last month to remove their option to attend meetings on MISO matters arranged by state or federal regulators. The change was made after a regular review of board procedures and is contained in the MISO Board of Directors Principles of Corporate Governance, which stipulates directors’ conduct.
The revision leaves regulator-board member exchanges to take place largely during public board meetings, Advisory Committee meetings, and annual stakeholder meetings. MISO said the change is effective following the board’s vote and was necessary to avoid the perception of partiality.
“The changes were clarifying edits to emphasize that board communications with stakeholders are most appropriate and useful in connection with open and public meetings,” spokesperson Brandon Morris said in a statement to RTO Insider. “MISO’s directors are mindful of their duties and independence as directors, as well as the independence of MISO, and are sensitive to perceptions of conflicts of interest or favoritism.”
Morris said the board has declined multiple meeting requests from separate MISO sectors in the past and said it is “best that MISO’s Principles of Corporate Governance align with the Board’s practice of not meeting separately with MISO stakeholder groups.”
“The changes do not change or limit in any way the interaction that MISO’s Board has with MISO stakeholders today,” he added.
During the grid operator’s March board meeting, Michigan Public Service Commission Chair Dan Scripps and Indiana Utility Regulatory Commissioner Sarah Freeman expressed disappointment with the rule change.
The Organization of MISO States, which is comprised of regulatory representatives from the 15-state footprint, said it does not have a position on the removal of regulator-scheduled meetings with MISO board members. The organization did not provide further comment.
FERC representatives did not return RTO Insider’s request for comment as to whether federal regulators will be affected by the changes.
Another governance rule change clarifies the Nominating Committee’s recommendation that the board pursue waivers to seat certain directors past MISO’s three-term limit. Board Chair Todd Raba warned last month that the board will likely have to authorize waivers to avoid an institutional knowledge gap, as multiple directors are on track to reach their term limits over the next few years. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.)
The Nominating Committee vets and selects board candidates for the membership’s consideration. It is comprised of select board members and two MISO stakeholders, one of whom is typically from a state regulatory commission.
The board will meet privately for a strategy planning session April 18-19 in Nashville, Tennessee. The meeting won’t be open to stakeholders because the topics involve attorney-client privilege.
With MISO still years away from allowing distributed energy resource (DER) aggregators to fully participate in its markets, the RTO hosted experts this week to discuss best practices in registering DERs and data sharing.
Voltus’ Emily Orvis said she thought it was valuable to talk about MISO’s current DER registration process even if the grid operator may be six years away from final compliance with FERC Order 2222.
The RTO has requested that the commission allow it to wait until nearly 2030 to introduce a wholesale participation model for DER aggregation. It said it first needs to replace its market platform before staff have the technological capability to comply with the order. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)
Orvis said MISO should standardize its enrollment processes for demand response, emergency demand response, load-modifying resources and dual-enrolled resources.
“The fact that there are disparate registration processes has a cascading effect,” she told stakeholders during a MISO DER Task Force conference call Tuesday. Orvis said that market participants must sometimes email sensitive customer data for LMR and emergency demand response registrations; she recommended staff adopt a single web portal for DER enrollments.
“The future is in some ways already here. We cannot wait until 2029 or whenever 2222 compliance is to figure out a more secure and streamlined registration process,” Orvis said.
She said MISO should modify its registration process so it doesn’t reject entire aggregation enrollments if a single site’s data is incorrect or changes. “For example, if one small site of 100 in an aggregation changes [its load-serving entity], the entire aggregation loses eligibility,” Orvis said.
Creation Energy founder and CEO Chris Hickman said DERs will be more useful to the grid if better data sharing is in place. He said he has always assumed an entity would step up to create and manage a collaborative tool for DER data sharing. Eventually, he said, he realized it was up to his team to establish the nonprofit registry they debuted earlier this year.
When DERs trigger grid issues, it’s because they’re incorporated with little to no operational visibility and control, Hickman said. He said DERs integrated with utility or RTO visibility and control can solve issues like poor power factor and phase balance.
“Regions like Australia, Germany, Ireland, California and Texas that have high penetrations of DERs have experienced cascading outages … and have identified a registry as the key component to help resolve issues,” Hickman said.
He said the industry has an opportunity to collaborate on a data exchange source, his organization’s Collaborative Utility Solutions, that could save billions of dollars. The nonprofit is funded by utilities’ memberships based on their size and competitive aggregators who pay for the data services. DER owners or operators are responsible for registering their assets’ information.
RTOs, state regulatory commissions, equipment vendors and other industry members are eligible for free subscriptions. Hickman said he plans to keep the subscriptions free, saying that if charged, the entities would recover their costs through utilities or consumers, effectively charging the consumer twice for the registry.
Hickman said membership costs will drop as the enrollment grows and administrative costs are dispersed.
“The more members we attract, the lower the costs go,” Hickman said. He said the system aims to replicate the Electric Power Research Institute’s (EPRI) Common Information Model.
EPRI’s Tanguy Hubert said the MISO region could house a program similar to the United Kingdom’s Flexible Power Initiative, where some DERs provide grid services by adjusting their power imports or exports.
Hubert said most of the U.K.’s DER-provided flexibility services are contracted without an advance capacity reservation for unplanned conditions. Only a fraction of capacity is contracted for planned situations under firm reservations, he said.
EPA on Tuesday announced it will propose new emission standards for cars and trucks that could lead to two-thirds of the total light-duty vehicles and 46% of medium-duty vehicles sold in 2032 being electric.
A second set of standards focuses on heavy-duty vehicles such as buses, construction equipment and utility bucket trucks. Both standards would go into place starting in model year 2027 and are built on standards already in place through 2026 that limit the amount of carbon dioxide vehicles can emit.
During a press conference Tuesday, EPA officials were tight-lipped about what exactly those amounts would be, but one official mentioned that light-duty vehicles would be limited to 82 g/mile by 2032. The standards would not mandate any specific technologies, and other carbon-cutting technologies outside of batteries will likely benefit from them, but experts outside the agency said that electric vehicles are the cheapest now.
Since President Biden took office, the number of EV sales has tripled, while the number of available models has doubled, White House Climate Adviser Ali Zaidi said at the press conference. EPA officials said the standards would improve air quality for communities around the country and avoid nearly 10 billion tons of carbon emissions, more than twice the entire country emitted last year.
They also said that they will cut fuel and maintenance costs, saving customers $12,000 over the lifetime of a light-duty vehicle as compared to a vehicle not subject to the new standards. Oil imports would be cut by about $20 billion, and the agency estimates the total benefits of the standards would exceed costs by at least $1 trillion.
The proposal aligns with commitments made by car manufacturers and U.S. states as they plan to accelerate clean technologies to include EVs as a growing part of future product lines, EPA said.
Legal and Supply Chain Challenges
The standards were developed using a process that EPA has used before when it sought to improve the mileage standards of internal combustion engines, which led experts on a call earlier in the day hosted by Environmental Defense Fund to say they should withstand any legal challenges.
“These regulations will reflect, in my view, the single most important regulatory initiative by the Biden administration to combat climate change to really reduce the worst outcomes of climate change,” Margo Oge, a fellow with ClimateWorks Foundation, said on the call.
Getting to nearly 70% EVs in the next decade is going to be challenge, but the industry was already heading this way, and the Inflation Reduction Act has funding that encourages more of the supply chain needed to build all those cars to move to domestic sources, said Oge, who worked at EPA for several decades until the Obama administration.
“We’re going to see massive, massive effort in the U.S. … to invest in all these elements,” she added. “The critical minerals are important. Battery components are important. Manufacturing facilities are important.”
There are already about 75 facilities across 24 states that are involved in the battery and critical materials supply chain, Oge said.
Advanced Energy United Director of Transportation Ryan Gallentine agreed that it was important for the U.S. to ensure its supply chains are increasingly domestic, or at least in friendly nations.
“I think ultimately, at least in the short term, it needs to be an all-of-the-above strategy for sourcing these materials,” Gallentine said in an interview.
The standards are being put in place in service of the overarching goal of limiting the worst impacts of climate change, and global politics should be put aside in furtherance of that overall goal as much as possible, he added.
Can the Grid Handle the New Demand?
Also on Tuesday, NERC, WECC and the California Mobility Center released an analysis of supplying EVs power, which did not take into account the new standards (projecting only as much as 30% of new light-duty vehicles being plug-ins by 2050) but discussed some of the power sectors challenges and opportunities. (See related story, NERC, WECC Outline EV Charging Reliability Impacts.)
The analysis laid out a number of issues with the distribution system’s capability of handling the new loads and other potential problems, but it noted that with enough planning, plug-in vehicles actually could benefit the grid by providing key services such as frequency response.
AEU’s Gallentine agreed with that assessment. Some changes to permitting laws to help expand the bulk power system on the federal side would help, but much of the work is going to be left to the states as they oversee the distribution system, he said.
“At the state level, we’ve been advocating for utility business model reform that would basically allow utilities to build in anticipation of that,” said Gallentine.
Utilities should be able to plan their systems to meet the needs of electrifying fleets and areas such as highway rest stops, where many EVs would charge at once, before that load shows up, he said.
“We need a lot of careful planning and coordination from folks at the state level to tackle the power-supply question,” Gallentine said. “And my concern is that states that aren’t doing that are going to end up with a much more expensive and less efficient deployment of this. I would say whether or not your state is supportive of EV policy, they owe it to all ratepayers to do this in a way that isn’t going to be expensive.”
ALBANY, N.Y. — Amid all the talk of electrons and dollars thrown around at the New York Energy Summit, the old chicken and egg metaphor popped up several times during the three-day event on April 4-6.
The state’s lofty climate goals are balanced by the need for the electricity fossil fuel produces, and there are multiple obstacles to replacing fossil fuel with new clean energy.
Chris Stolicky, chief of gas system planning and reliability at the New York Department of Public Service, said rapidly approaching statutory emissions reduction requirements are running into the realistic need to maintain “peaking assets to offset reduced capacity.”
A chicken and egg proposition, in other words.
Panelists applauded New York for modernizing its grid but worried that attempts to decarbonize too quickly without boosting clean energy generation threaten the state’s ability to both reliably keep the lights on and achieve its goals.
Goals vs. Needs
New York’s conundrum is how to ensure grid reliability and resilience as it calls for fossil fuel resources to be replaced by intermittent resources.
The state must “fill in the gaps for when the sun goes down or the wind breaks,” said Dr. Ingo Stuckman, founder of the Zero Emission think tank, who moderated the summit’s Alignment of Wholesale Markets with Decarbonization Goal panel.
“We have to make sure we have a market that covers the needed resources to maintain a significant amount of supply to meet extreme conditions,” said Mike DeSocio, director of market design at NYISO. But he added that the “outlook is delicate.”
“There are plenty of projects in the pipeline; the issue is we need some projects to be commercial, and that we have not seen yet,” DeSocio said, referring to the ongoing backlog of projects in NYISO’s interconnection queue. (See NYISO Previews Plan to Expedite Interconnection Queue.)
Rachel Goldwasser, general counsel and vice president at Key Capture Energy, contended that energy storage resources could solve many of these problems, but “making sure [storage resources] can be interconnected and that the market signals work … has taken longer than expected.”
DeSocio agreed that storage resources potentially present an elegant solution, but “the jury is still out.”
“We need to make sure that all the pieces are moving together on the chess board,” he said, referring to how one project’s delay in the interconnection queue can impact the timing or viability of another.
NYISO “would love to add storage” he added, but “we want to be careful not to add it too quickly because we don’t have the renewable resources yet to charge storage en masse.”
He also flagged the short duration of most current storage technology: “We haven’t seen storage in the queue that can be expected to run for 10, 12 or 14 hours,” which is the current level of support needed during a grid emergency.
In response to DeSocio’s comments, Goldwasser said, “There’s going to be a transition period where we’re going to be uncomfortable,” and if stakeholders do not address these problems, then “we’ll be in a position where we’re contracting with fossil plants to stay online.”
Cue the Queue
New York’s ability to rapidly integrate emissions-free resources has been hampered by ongoing problems with NYISO’s interconnection queue, which has been pushed to the limit since the state’s Climate Leadership and Community Protection Act (CLCPA) passed in 2019.
“We’ve grabbed the low-hanging fruit,” said Andrew Bernstein, managing partner at Kearsarge Energy, referring to residential solar projects requiring little permitting or study. “Now the question is how to get commercial and industrial projects interconnected.”
There are “tons [of projects] in queue right now. … The question is how do we reduce costs,” he said.
Daniela Pangallo, director at Nautilus Solar (NYSE: NLS), said interconnection costs are multiplied first by inflation and then by the amount of time the process takes to complete, causing some projects to exit the queue entirely.
Joe White, distributed generation ombudsman with Consolidated Edison Company of New York (NYSE: ED), said in response to these growing challenges state agencies and utilities have increasingly integrated stakeholders into these studies to identify “things that are great about the interconnection process … and what items need improvement.”
“We take that feedback and look at any software enhancements, training and opportunities to reinvent the interconnection process, and we put those into motion,” he added.
But more needs to be done to prepare for the future.
Referring to New York’s transformer shortage, Ryan G. Hawthorne, vice president with Central Hudson Gas & Electric (NYSE: CHG), said the state has a “chicken and egg problem.” Do developers push new projects through NYISO’s queue, which risks costs rising, or invest in aging assets to make them more resilient, which may not necessarily be the best long-term solution but offers a more predictable outcome?
What is a certain, he said, is that to ensure future reliability and resilience “we need [investments] in our system to be able to address more frequent and impactful [extreme weather events].”
“We’re entering a period of a lot of uncertainty related to project development,” said Kyle Collins, director of business development at Hydro-Quebec US, where interconnection concerns and questions about renewables’ ability to meet future peak loads has forced generators to “leverage as much as [they] can out of the existing system.”
In the building discussion, moderated by RTO Insider Editor Rich Heidorn Jr., panelists identified how legal mandates and policies, such as the Local Law 97 or the CLCPA, have pressured developers to decarbonize a sector of society that accounts for 30% of New York’s emissions without impacting consumers. (See NYC Proposes Rules to Implement Building Emissions Law.)
Modernizing New York City’s building stock to these new net-zero requirements will be particularly difficult.
These laws “created some challenges” and forced developers “to think very carefully about anything [they] deliver,” said Michael Daschle, senior vice president of sustainability at Brookfield Properties.
Namely, should developers and building owners invest now to upgrade their buildings to comply with new net-zero energy requirements or suffer financial penalties for not decarbonizing that might be less economically painful in the near-term?
Daschle explained that developers are increasingly concerned about whether all-electric homes will “actually be marketable” because they will “require more equipment … and are significantly more expensive.”
Additionally, much of the state’s building stock is old, noted Samantha Pearce, vice president and director of sustainability at New York State Homes and Community Renewal, the state’s affordable housing agency. Electrifying them with new technologies, such as heat pumps, is not only expensive but requires a lot of space, she said.
“We now have to accommodate larger mechanical room spaces,” and in some residential buildings this has created economic “domino effects” that place new “limitations and considerations” into affordable housing decisions, Pearce said.
Similarly, Dawn Fenton, vice president at Volvo Group North America, said the transportation sector is undergoing a “paradigm shift” and needs to move “beyond the pronouncements and lofty goals. … Yet there’s not been a realization of what are the challenges behind [a net-zero future] and that it is not as easy as mandating it as so and it will be so.”
She added, “I think people are starting to recognize the challenges of charging infrastructure or the challenges of permitting reform and all the work that needs to be done to actually realize [the state’s] goals.”
Kara Podkaminer, senior adviser for sustainable transportation at the U.S. Department of Energy, said “there is a misalignment in planning timelines, where in six months you can get an electric vehicle, … but the timeline to get the charging infrastructure or upgrades can be more like a decade.”
Fenton and Podkaminer agreed that consumer education and awareness is the biggest “nut left to crack,” as many people remain skeptical about how decarbonization will impact them, either from an economic, social or environmental perspective.
They also agreed that informed consumers help guide decision-makers to where the needs are greatest.
We need to “come up with a plan together that meets all of our needs in a way that is more streamlined … and produces less uncertainty” Podkaminer said.
“This is a difficult transition for everybody,” Fenton said, but if New York does not address these unresolved issues and “make it as easy as possible for everybody to take part of this transition” then the state will struggle to reach net-zero.
Hawthorne summarized New York’s chicken and egg problem using an example drawn from the transportation sector, but which could be applied to every sector needing to be decarbonized: Do you “want electric vehicles first or their charging stations?”
New Mexico Gov. Michelle Lujan Grisham vetoed large portions of a tax package on Friday, cutting out income tax credits for electric vehicles, energy storage systems and geothermal electricity production.
The tax credits fell victim to budgetary caution on the part of the governor, who said items she vetoed within House Bill 547 would have reduced the state’s annual revenue by $1.1 billion.
“These large reductions would risk significant funding cuts in future years for critical services,” the governor said in a statement.
Friday was the deadline for Lujan Grisham to sign bills from the 2023 legislative session. Bills on which the governor took no action were “pocket vetoed.”
Among this year’s pocket vetoes was HB 365, which would have established a geothermal center of excellence at the New Mexico Institute of Mining and Technology along with grant funding for developing geothermal projects. The House passed the bill on a 63-3 vote; the Senate vote was 37-0.
Camilla Feibelman, director of the Sierra Club Rio Grande Chapter, said the tax credits for EVs, energy storage and geothermal development would have been “a drop in the bucket” of New Mexico’s budget. And the credits would have boosted emerging industries, Fiebelman said in a statement on Friday.
“We are facing a climate emergency that requires emergency action, not vetoes,” Fiebelman said.
Friday’s vetoes were just the latest disappointment for environmental groups regarding the state’s 2023 legislative session, which saw few climate-related bills make it to the governor’s desk.
Senate Bill 520, which set targets for reducing greenhouse gas emissions, failed to make it out of its first committee. (See Emissions Bill Stalls in New Mexico Senate.) A similar bill failed in the legislature’s 2022 session, but advocates had hoped it would fare better during this year’s longer, 60-day session. Sessions in even-numbered years are 30 days and are focused on budget issues.
“It felt like we had really good momentum, but it fell apart early in the session,” Ben Shelton, political and policy director with Conservation Voters New Mexico, told NetZero Insider. “There just was not the appetite to fight with the oil and gas industry and hold them accountable.”
Shelton said another disappointment was an effort to establish a “transition division” in the Economic Development Department to pursue funding for communities transitioning away from an oil and gas economy. Language establishing the division got rolled into HB 12, the Advanced Energy Technology Act, Shelton said, and the bill never made it out of committee.
Another failed bill was HB 426, a proposal for a low-carbon fuel standard. It was at least the third try for the state legislature to pass an LCFS bill, and Lujan Grisham’s administration had backed the proposal. (See LCFS Bill Emerges in NM House as Session Nears Close.)
The bill cleared two committees and was sent to the House floor, where it was never voted on.
In remarks on Friday, Lujan Grisham said New Mexico would continue to be a leader on environmental issues, the Santa Fe New Mexican reported. She said the Sierra Club should be celebrating the creation of the Land of Enchantment Legacy Fund, which was established by SB 9.
The $100 million conservation fund will support water stewardship, forest health, outdoor recreation and wildlife species protection. Lujan Grisham signed the bill last month along with SB 72, which creates a fund to carry out a wildlife corridor plan, aimed at reducing vehicle collisions with wildlife.
Another bill signed into law was SB 53, which prohibits storage of high-level radioactive waste in New Mexico without the state’s consent. The bill was reportedly intended to block Holtec International’s proposed nuclear waste storage project in southeast New Mexico.
Michael Daschle of Brookfield Properties said his company is preparing two designs for a new building: one all-electric, and one that will incorporate natural gas. The all-electric version would be 40 feet taller to accommodate additional equipment and significantly more expensive to build, but it would carry the cachet of being emissions-free, which means a lot to some prospective tenants. “You have to go back to your investors … and say, ‘Look, this is not necessarily going to achieve the same returns as a traditional gas building, but there are all those other considerations to think about.’”
Mike DeSocio of NYISO raised a warning flag on retiring fossil fuel generation before new renewable energy projects come online.
“There’s plenty of projects in the pipeline; the issue is we need some projects to be commercial, and that we have not seen yet,” he said. “So the outlook is delicate. … We are expecting the first wave of peaker retirements in 2023, and the next wave would be in 2025.
“At the same time, we’re staring at a future reserve margin of zero-ish, maybe negative, and we’re very interested to see how the forecast might come out.”
Dawn Fenton of Volvo Group North America spoke about the transition away from internal combustion engines in heavy-duty vehicles. “I think we’re in a real paradigm shift in the transportation sector. … I’m also excited about the fact that I feel we’ve hit a transition even in the last several months, that we’re getting beyond the pronouncements and the lofty goals. … We’re finally getting to the point of people recognizing the challenges of charging infrastructure; the challenges of permitting reform; all the work that needs to be done to actually realize this goal.”
Shweta Kapadia of Crayhill Capital Management highlighted the impact that financial volatility has had.
“I think one thing that … developers are doing and we as vendors are doing is, we are very cautious when we are signing a [power purchase agreement] because we did see a lot of projects that signed PPAs … are now underwater because prices have gone up.”
Maureen Leddy, director of the New York Department of Environmental Conservation’s Office of Climate Change, said the state’s climate law requires her agency to promulgate key emissions-reduction regulations by Jan. 1, 2024. Given the complexity of those rules, and the amount of stakeholder input and feedback DEC will need to seek out, the statutory deadline is “very ambitious and highly unlikely.”
Kara Podkaminer, of the U.S. Department of Energy’s Vehicle Technologies Office, spoke of the importance of not only redesigning central components of modern life but doing it so that they will be functional together.
“The transportation system and the power system are two of the largest systems we’ve ever made, and now we need to actually make them work together, because if we don’t, we actually need to build more infrastructure.”
Marguerite Wells of Invenergy said she does not expect a significant increase in onshore wind capacity in New York, beyond what is already in the pipeline. “Most of the windy hilltops already have turbines on them, and most of the remaining windy hilltops are nowhere near transmission lines. So I don’t believe there’s all that much more wind resources to build out because fundamentally, that wind is competing in every [request for proposals] with solar.”
David Whipple of Empire State Development was asked why a green energy manufacturer might build a new factory in New York rather than Georgia or some other state where the cost of doing business is lower.
He cited net-zero policies, which have become an important consideration for some corporations: “If they want to manufacture this technology with green energy, they’re going to get there a lot faster in New York than they would in many Southern states.”
Joe White, Consolidated Edison’s (NYSE:ED) distributed generation ombudsman, was asked with his fellow panelists what had been the best thing and worst thing to happen in recent history. He identified the COVID-19 pandemic as both best and worst, because it has been so disruptive and because so many people have adapted so well in response: “On both sides of the meter, we’ve had to be more creative, more innovative than we ever have before in trying to get things done from an office and field environment.”
ISO-NE and NEPOOL last week asked FERC to approve changes to the Inventoried Energy Program to reflect recent volatility in the global natural gas market and gas contracting prices in the region.
The program was designed as a stopgap for longer-term market reforms to ensure winter reliability and is designed to pay resources for maintaining inventoried energy during the next couple winters. The RTO initially filed the program in 2019, and it was approved by FERC in 2020 to go into effect for the winters of 2023/24 and 2024/25.
Russia’s invasion of Ukraine last year led European nations to seek alternate sources to Russian gas, which has increased volatility greatly. Demand from Asia has also gone up in the interim, ISO-NE’s consultant Todd Schatzki of the Analysis Group said in testimony filed at FERC.
“Since the commission’s acceptance of the IEP, global energy markets have experienced dramatic and unprecedented changes in pricing levels and volatility,” ISO-NE said.
One of the most significant changes was to replace the fixed rate for resources procured in the IEP to an indexed rate that will be able to reflect any changed prices going forward, as the recent volatility is expected to last for the next couple winters. The initial program featured both a forward and spot rate, allowing resources to sign up ahead of time or during the winter, and both of those are moving to indexed pricing.
The forward rate FERC approved was $82.49/MWh for inventoried energy, but the new price will be based on a formula using the price for liquefied natural gas at the “Dutch TTF” (Title Transfer Facility), a proxy for European prices that have recently set the price of LNG in the entire Atlantic basin.
The formula also includes a liquidation price to reflect the possibility that New England generators might procure too much LNG, which would have to be sold after the winter season when prices are typically lower.
The base rate is capped at $288/MWh, which reflects the opportunity cost from participating in the IEP and liquidation costs and is based on the price needed to secure inventoried energy given real-world constraints.
The spot price now in place is just $8.25/MWh, but the RTO asked FERC to change that one-tenth of the applicable base payment rate, which is consistent with the current market design.
The updates also include changes to natural gas contract eligibility requirements and fuel allocation for shared fuel inventory, which are meant to be better aligned with current contracting practices in New England.
IEP participants will have to submit contracts that do not restrict when the gas can be called on during a day beyond the North American Energy Standards Board’s Wholesale Gas Quadrant scheduling and nomination standards.
The currently effective rules are also too restrictive, ISO-NE and NEPOOL said, because they require a level of gas delivery firmness that is not commercially available from the interstate pipelines that serve New England, so that part was updated to reflect market realities.
If a natural gas contract specifies an indexed strike price, then that specified index must be at one of the Northeast trading locations for which Platts publishes a daily value in order to ensure the contract in question reflects regional prices.
ISO-NE and NEPOOL asked FERC to make the changes effective June 6, which will ensure the rules attract inventoried energy for next winter given the increased volatility in natural gas prices. The new indexed rate will also make it easier for market participants to hedge their program costs.
“Without the proposed changes to reflect actual market prices and contracting practices, the current commission-accepted IEP runs the risk of providing insufficient incentives for participants to procure and provide inventoried energy when needed to ensure reliability on the coldest winter days, when fuel supplies are stretched to their limits,” the filing said. “Relying on well established and reliable price indices ensures that the IEP is providing accurate price signals reflective of the actual costs of providing the service, while avoiding overcompensation at the expense of regional consumers.”
The Institute for Energy Economics and Financial Analysis projects a steady decline in U.S. coal-fired power generation. | Institute for Energy Economics and Financial Analysis
