FERC last week granted a petition from a company looking to build an undersea transmission line to Puerto Rico, affirming several of the developer’s questions about its status as a utility and weighing in on whether the project would make the island territory’s transmission system subject to FERC’s jurisdiction (EL23-14).
The company, Alternative Transmission Inc. (ATI), filed the petition for declaratory order in December. It asked FERC to confirm that it could qualify as a utility and therefore be able to submit applications asking for orders directing other utilities to interconnect with or provide transmission services for Project Equity, its Puerto Rican project.
It also asked whether, if FERC were to direct interconnection or transmission to Puerto Rico as part of the project, those orders would “provide a basis for the commission to exercise plenary jurisdiction over Puerto Rico’s electric transmission system or utilities, which have not previously been regulated by the commission.”
FERC first said that its answers to most of the questions would depend on the specifics of an actual project application and any proposed interconnections. But it confirmed that ATI could qualify as a utility and could submit applications asking for an order requiring interconnection or transmission services. It could also therefore be a target of those applications by others.
On the jurisdiction question, FERC said that, unless there was an order issued pursuant to Federal Power Act Sections 210 and 211 (requiring interconnection or transmission), the interconnection that ATI is proposing between Puerto Rico and the continental U.S. would in fact result in the territory’s utilities becoming subject to FERC jurisdiction.
Those sections do provide an exemption though, the commission said.
“Upon receipt of valid applications under Sections 210 and/or 211, the commission could issue orders pursuant to those sections of the FPA allowing interconnection and/or transmission of energy between Puerto Rico and the interstate transmission system while retaining the jurisdictional status quo such that Puerto Rico’s electric utilities would not be ‘public utilities’ under Section 201e of the FPA,” it said.
However, FERC would still have jurisdiction of Puerto Rico’s utilities as part of other FPA sections including 210, 211, 212, 215 and “any other FPA provisions that provide for jurisdiction over Puerto Rico’s transmission system and its utilities.”
MISO responded to unease over its proposed capacity accreditation methodology Friday with a workshop to show stakeholders that it lines up with a recent report on accreditation design principles.
The RTO invited a representative from Energy Systems Integration Group (ESIG), which released the report last month, to the workshop. However, stakeholders continued to insist that accreditation should exist to simply reflect the reliability value of units, not send new capacity procurement signals.
Telos Energy’s Derek Stenclik, who serves on ESIG’s Redefining Resource Adequacy Task Force, emphasized that “there is no such thing as perfect capacity.” He said accreditation should hit a “sweet spot between reliability and economic efficiency,” making sure the methodology sends price signals to new market entrants.
MISO said Stenclik was not advocating for any particular accreditation method but laying out options.
ESIG’s report recommends that grid operators consider accreditation designs that evaluate energy availability during risky periods, use a similar and simplified method to accredit all resources, and align incentives in both capacity accreditation and real-time performance. That would “not only simulate availability during typical risk periods but ensure performance during actual scarcity events,” according to the report.
MISO is proposing all resources’ accreditation be predicated on availability during “resource adequacy hours,” or conditions with emergencies or tight supply. The methodology will also adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s direct LOLE piece would replace the RTO’s use of unforced-capacity values that rely on historic forced-outage rates.
The move to a marginal accreditation methodology would assign solar generation near-zero capacity credits within the decade. The thought is that an influx of solar generation is only helpful to a point and will shift daily generation peaks to when the sun sets.
MISO’s preferred accreditation design was contested during a Resource Adequacy Subcommittee meeting earlier this month. Stakeholders proposed several revisions and a pair of motions opposing the process. (See MISO Stakeholders Debate Capacity Accreditation, RA.)
Stenclik said accreditation designers should decide whether their philosophy is valuing capacity while determining the next-best investments, or simply assessing the units’ historical performance. He said a marginal approach arrives at saturation points for wind, solar and storage more quickly than one based on past operations.
ESIG concluded that accreditation should be tied to actual operations and that a combination of simulated, prospective capability and historical performance captures a wider range of risks, he said.
“If we’re only looking at how my portfolio did during risk periods in the last three years, my risk periods in the next three years are going to be very different as the resource transition continues,” Stenclik said. He said accreditation can draw on “a matrix of risk hours that are both past- and forward-looking.”
He said accreditation could be surveyed using a load-serving entity’s entire fleet. RTOs take stock of the LSE’s total supply side and demand-side resources and determine the total risk and benefits they introduce to the system, Stenclik said.
During the workshop, stakeholders asked whether MISO is open to removing marginal calculations from its accreditation, arguing it will undervalue capacity.
Zak Joundi, the RTO’s director of resource adequacy coordination, said the workshop was not intended to host another debate on the accreditation proposal. He said staff will continue vetting the accreditation proposal in the stakeholder process.
“It’s not like we just rolled this out. This has been 18 months of discussion,” he said of MISO’s proposal.
During the recent Gulf Coast Power Association’s annual MISO/SPP conference, MISO Independent Market Monitor David Patton said, “If we’re brave and we accredit resources right, the lights won’t go out. But it remains to be seen whether we do that.
“We need to be honest about the limitations of different resources,” he added.
Patton said different resource classes have different contributions to reliability. He said MISO should accurately assess those characteristics and known fuel issues by season to inform accreditation.
Signs Point to Renewables, Storage
No matter what happens with MISO’s accreditation proposal, the grid operator is certain to be awash in renewable energy, a market analyst said recently.
Ascend Analytics’ Brent Nelson said during a March webinar that high natural gas prices, solar generation and standalone storge tax credits and increased demand for clean energy mean MISO and PJM renewable developers are eager to begin construction.
“The kid in the candy shop is the analogy here,” he said, adding that there’s currently a “land rush” to snap up optimum sites for wind and solar resources.
Brent said despite gas prices dropping in the past few weeks, there’s “a pretty permanent long-term structural uplift in the market expectations.” He also said there’s “regulatory concern over stranded-asset risks” on new natural gas plants.
“Storage is the pretty clear new capacity resource,” he said.
Nelson said multiple RTOs are struggling with how to accredit capacity to meet reliability standards in a transitioning fleet mix. He said he doesn’t see good answers.
“I think one of the things we’ve seen over that last year is that there’s been a systemic underestimation of critical system risks in cold weather,” Nelson said. “If the critical system condition that you’re worried about is when the wind’s not blowing, by definition that’s the time that you’re worried, then you have to rethink how you accredit a resource.”
Nelson predicted that both PJM and MISO will see coal resources retire without extensions. He said coal will get “squeezed out” of markets, unable to compete with solar and wind.
High natural gas prices will keep energy prices high in the near term, but substantial renewable energy buildout will eventually bring them down, he said.
“I think the concept of baseload is a false construct. What you need is to meet demand. And so, if you have variable supply, you want some other variable supply that can fit around it,” Nelson said. “Baseload as a concept isn’t something that we need. What we need is something that will deliver reliability and energy at minimum cost.”
Nelson said he doesn’t expect MISO capacity prices to hit net cost of new entry in next month’s 2023/24 planning year auctions, but he said clearing prices are entering an era of instability. MISO’s capacity market will “oscillate between near-zero and near-price cap levels” for years as utilities lean on the optional market to make up their needs, Nelson said. For that reason, MISO utilities will strive to build, own and contract capacity outside of the market, he predicted.
NEW ORLEANS — A year after it was announced, Cleco’s Diamond Vault carbon sequestration project is in the thick of an engineering study that will determine its design and construction.
Diamond Vault is planned to capture and sequester up to 95% of the carbon emissions from Cleco’s (NYSE: CNL) petroleum coke- and coal-fired Brame Energy Center’s Madison Unit 3 by 2028. The unit emits about 4 million tons of carbon dioxide per year and is one of the biggest sources of carbon pollution in Louisiana.
The project will use an amine-based carbon capture technology employing an amine solvent that has a reversible reaction with CO2. The sequestered CO2 will be converted into a sludge that will bond with rock over time in geological vaults below the Brame Energy Center.
During the Gulf Coast Power Association’s (GCPA) MISO–SPP conference earlier this month, Cleco Chief Compliance Officer and General Counsel Bill Conway said Diamond Vault is the result of a convergence of economic worries and “concern over our children’s, children’s children.”
“World capital has come to the conclusion that climate change is a problem,” he said.
Cleco secured $9 million in congressional funding for the $12 million engineering study, expected to be completed next year. In an emailed statement to RTO Insider, the company said it cannot speculate on the study’s results before its completion and declined to answer questions on whether Brame is proving to be a suitable site or whether the project might keep Madison 3 operational longer through emissions control.
The utility is seven months into the 21-month study. Jennifer Cahill, corporate communications director, called the engineering study a “major step in making Project Diamond Vault a reality.”
Cleco said if the study proves successful, it will work to secure the $1.1 billion to $1.4 billion needed for the project through the federal government’s $85/ton tax credit for carbon storage. Construction would begin at the end of 2025, the utility said, and it does not expect to require rate increases to fund the project.
The billion-dollar estimate matches the cost of Madison 3 itself.
Conway said the federal government’s tax credit makes the project viable. He also said amine-based carbon capture is already a proven method, though not at the scale of Cleco’s envisioned project.
He said it would be “economically catastrophic” to prematurely shutter Madison 3 because it was built in 2010 and ratepayers might be forced to foot its stranded costs.
Cleco estimates Diamond Vault will require about 200 MW to run, about a third of Madison 3’s output. Conway said those megawatts will likely come from solar generation additions.
He said he believes carbon credits will soon become a mandate and that Cleco is better off getting ahead of the issue, funded largely by “Uncle Sam.”
“We think we have a very good proposition to sell to the Louisiana Public Service Commission,” Conway said.
Cleco has started “intensive community outreach” to earn public support on the project, he said. However, he said not many people live in the site’s vicinity.
“So far, because of where we are, because we’re not going under a major waterway, because the site is surrounded by timberland, there seems to be good community acceptance,” Conway said.
The company says Madison 3 is a good candidate for onsite carbon capture and storage because it’s a newer plant with relatively low sulfur emissions. The plant is also situated on a large site with “suitable” geological formations for permanent carbon sequestration “directly below the Madison 3 unit” that won’t require pipeline transportation.
Cleco said it’s in discussions to sell the unit’s output to third parties that need around-the-clock available clean energy to comply with low-carbon fuel standards.
“If we are successful in this effort, we will be able to substantially reduce our rates and improve customer affordability,” the utility says.
Conway predicted Louisiana will be ripe for other carbon capture and sequestration projects.
During the same GCPA panel, Tenaska Power Services’ Bret Estep said carbon-capture developers will have to present their case that Louisiana isn’t going to be targeted as a “dumping grounds” for carbon. He argued that Louisiana is already an industrial hotspot that won’t be able to exist in the future without CCS operations.
“I think without this, we’ll be left with brownfields that will take decades, centuries to remediate,” he said of Louisiana’s industrial landscape.
The New York Public Service Commission on Thursday again extended utilities’ deadline to procure dispatch rights for bulk energy storage systems — this time to the end of 2028 (Case 18-E-0130).
The PSC’s original energy storage order in December 2018 had specified a Dec. 31, 2022, deadline for the six utilities to secure contracts of up to seven years’ duration for qualified energy storage: 300 MW for Consolidated Edison and 10 MW each for Central Hudson Gas & Electric, New York State Electric & Gas, National Grid, Orange and Rockland, and Rochester Gas and Electric.
Only National Grid reached its target in its first-round solicitation.
In April 2021, the PSC granted the utilities’ request to extend the deadline to Dec. 31, 2025, and expand the maximum contract duration to 10 years.
But after the second round of solicitations, the executed contracts totaled just 120 MW — 100 MW in Con Ed territory and 20 MW in National Grid territory — though Central Hudson is reportedly in final negotiations for 50 MW.
Last November, the utilities petitioned to extend the deadline to Dec. 31, 2028, and to expand the maximum contract duration to 15 years.
The utilities said that recent changes — including a new 30% federal tax credit for energy storage expenditures and their decision to cut the cost of charging — will improve future solicitations.
Given the extended period sometimes required for permitting and interconnection, the utilities said in their petition, it was unlikely projects contracted in 2023 would be in service by the end of 2025.
And they said their discussions with bidders suggested that the option of a 15-year contract would result in more competitive bids because it would allow a longer period of amortization and because current NYISO market rules provide limited revenue.
The PSC approved the utilities’ request Thursday and directed them to file tariff amendments by June 1.
Energy storage is a critical aspect of the clean energy transition New York is undertaking — replacement of steady oil and gas power with variable wind and solar power will require a significant buildout of short- and long-duration storage to smooth out fluctuations and match supply to demand.
The Department of Public Service is currently reviewing a proposed framework to get 6 GW of energy storage online by 2030. It would be the most ambitious storage goal of any state and would, for a brief period, be able to supply at least 20% of the peak electrical load in New York. The state’s current energy storage target is 3 GW.
“New York’s energy storage deployment policy has effectively strengthened the market for developing and installing qualified energy storage systems in New York,” PSC Chair Rory Christian said in a news release later Thursday. “The development and introduction of energy storage will build flexibility into the grid and advance New York’s ambitious clean energy goals.”
The PSC vote was 6-1 in favor of the extension. Commissioner Diane Burman voted against the order, voicing concern about the fairness of changing the rules midway through the process.
Commissioner John Howard raised concerns about the escalating of cost of storage since the 3 GW goal was set, saying it was just one instance of uncertainty and wishful thinking as the energy transition is planned. “This is how I view a lot of our decarbonization efforts — they’ll take longer, and they’ll cost a lot more,” he said.
New Jersey’s growing focus on cutting building emissions and reducing natural gas use is drawing criticism from environmentalists who claim the state is not doing enough and business interests that say it’s going too fast.
With solar energy a staple in New Jersey and the offshore wind industry rapidly advancing, the state recently has put the spotlight on natural gas. Several proposed policies aimed at cutting gas emissions have exposed fierce disagreements at public forums and triggered criticism from opponents and even friendly groups, such as environmentalists.
The New Jersey Board of Public Utilities (BPU) on March 6 voted to establish a stakeholder process to develop plans to reduce emissions from the gas sector. The board’s focus will include exploring business models that could keep the “gas system intact while accounting for a shrinking customer base” and the “elimination of subsidies that encourage unnecessary investment in natural gas infrastructure,” according to the order.
The effort would also explore “alternative programs and investments that could provide natural gas utilities with new revenue streams and promote good-paying jobs, including union jobs.” The agency will also look at “electric grid readiness to handle electrification of building heating and cooling, as well as transportation.”
Gov. Phil Murphy triggered the initiative with a Feb. 15 executive order calling for the BPU to develop a natural gas utility plan that would help achieve the state’s goal of a 50% reduction in GHG emissions below 2006 levels by 2030. The same day, Murphy signed an executive order that created a policy to electrify 400,000 dwelling units and 20,000 commercial spaces by the end of 2030.
In a separate move March 9, the Senate Environment and Energy Committee posted for discussion a bill (S3672) that would pave the way for electricity to replace gas as the main fuel for building heat and hot water systems.
The bill would direct the BPU to establish a “beneficial building electrification” program that would reduce emissions, reduce costs “from a societal perspective,” and promote the increased use of electricity in off-peak hours. It would also require the state to prepare for a “change in end-use equipment from a non-electric type to an efficient electric type for any building end use, including water heating, space heating, industrial process, or transportation.”
In addition, the bill requires the BPU to develop natural gas emissions reductions targets for each utility in the state.
Next Frontier
The focus on natural gas addresses two of the state’s largest sources of GHGs, with electric generation — heavily dependent on gas — accounting for 20% of emissions and residential, industrial and commercial buildings, 34% in 2019, according to the New Jersey Department of Environmental Protection (DEP). Transportation accounted for 39%.
The discussion about reducing the role of natural gas is “the next frontier in the clean energy and climate space,” said Eric Miller, New Jersey energy policy director for climate and clean energy at the Natural Resources Defense Council.
“It’s become increasingly clear over time what a big source of emissions” the production and burning of natural gas represents, Miller said. And New Jersey, which has no domestic gas production industry, could cut those emissions by replacing the fuel with the state’s rapidly developing solar and wind electricity generation sources, which also provide local jobs and economic development, he said.
Yet fossil fuel interests say the state should explore alternatives before plunging into what they say will be a highly expensive bet on electricity. In opposition to S3672, the Fuel Merchants Association of New Jersey (FMANJ) — which represents oil heat retailers, motor fuels distributors and industry suppliers — and the New Jersey Propane Gas Association, have waged a campaign using an online advertisement under the headline “Don’t Touch My Gas Stove.”
The campaign, which goes under the name Smart Heat NJ, says the bill would create a shift that “is not only expensive, but [represents] a total overhaul of the rules for housing, environment, and energy, in short the entire economy of New Jersey.”
The Senate committee has yet to discuss the bill, which was pulled from the agenda. Sen. Bob Smith (D), the committee chairman, told the meeting that once it was posted “we got calls from a whole bunch of groups that we had not heard from before,” and co-sponsor Sen. Andrew Zwicker (D) wanted to meet with them before the bill goes forward.
Eric DeGesero, executive vice president for the FMANJ, said Smith’s quick withdrawal of the bill shows that opposition goes beyond just fuel merchants.
“There are a lot of interests in the state that have a lot of concerns about mandated electrification as the only path forward in the building sector,” he said.
But Miller said the Smart Heat NJ campaign is “misinformation in service of fossil fuel revenues at the expense of more choices and more opportunities for New Jersey’s residents and businesses.”
“This bill doesn’t go after gas stoves. It doesn’t make anyone do anything,” he said. “The onus is not on residents, homeowners, apartment dwellers, businesses; it’s on the utilities to stand up programs that provide incentive education, workforce development, to make electrification a legitimate option for individuals and for businesses.”
Cutting Generator Emissions
The state’s earlier efforts to address building emissions have also been contentious. In January, the DEP altered a package of rules aimed at cutting GHG emissions in electricity generation and elsewhere: It removed a measure that would have prevented the agency from issuing permits for new fossil fuel-fired boilers in certain situations. The DEP excised the rule after opposition from business and fuel groups. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)
Opponents of the ban, including the FMANJ, are pushing a bill (S2671) that that would prohibit any state agency from adopting regulations that “mandate the use of electric heating systems or electric water heating systems as the sole or primary means of heating buildings or providing hot water to buildings.”
New Jersey has not yet made such a mandate, but the state’s Energy Master Plan, which the Murphy administration is updating, calls for the building sector to be “largely decarbonized and electrified” by 2050.
Those policies draw support from environmental groups, which question the state’s commitment to reducing natural gas use in other areas, particularly electricity generation.
State officials faced sharp criticism from environmentalists at a March 7 DEP hearing on the department’s emissions reduction priorities over the next few months. The measures include rules to limit emissions from generating units, starting with a maximum of 1,700 pounds of CO2 per MWh of electricity generated in 2024 and reducing the ceiling to 1,000 pounds in 2035.
“These facilities would have the opportunity to put controls on to stay running, or they would have to shut down by the 2024 date,” said Paul Baldauf, a DEP assistant commissioner who presented the plans. “It’s likely many of them will make a decision to shut down because it may not be cost-effective to put additional controls” in place, he added.
The state has 32 gas-fired generators, which comprise more than 10.5 GW of capacity, according to the DEP, and generate about 45% of the state’s electricity, according to the U.S. Energy Information Administration.
The state also is seeking to cut emissions on campuses, where it may not be feasible to electrify the heating in individual buildings, but where emissions could be reduced across all structures through planning.
But environmentalists at the meeting questioned how the state can be both seeking to reduce natural gas use and allowing for development of gas-fired generation.
“We clearly need to reduce our use of natural gas,” said Ken Dolsky, a steering committee member of Empower New Jersey, a coalition created to oppose fossil fuel-fired plants. He noted that the state has seven gas-fired plants either under consideration or moving ahead.
“It just doesn’t make any sense to build new gas plants that have a 30-year lifetime, in order to pay for themselves, while at the same time you’re trying to reduce natural gas,” he said. “It just boggles the mind that we would allow ourselves to get deeper and deeper into the hole of greenhouse gases, while at the same time making these tepid efforts to actually reduce greenhouse gases.”
Doug O’Malley, director of Environment New Jersey, called it “a clear incongruence” in the state’s goals.
Baldauf acknowledged that “you’re correct” that the DEP’s upcoming projects do not include a moratorium on gas-fueled plants.
Dissatisfaction with the state’s position also emerged at a Feb. 28 public hearing for a 630 MW gas-fired plant in the Keasbey section of Woodbridge, developed by Competitive Power Ventures. Most of the more than two dozen speakers at the hearing were either local residents or representatives of environmental groups concerned that the state would allow a new plant to open in a community already designated an environmental justice area.
“We are already overburdened,” Angeline Walters, a Woodbridge resident with three children, told the hearing. She noted that the developer operates clean energy plants in other parts of the country.
“It’s completely irresponsible to keep damaging the health of our communities and the environment when we have better ways,” she said.
FERC on Thursday acted to shore up power grid cybersecurity defenses by approving NERC reliability standard CIP-003-9 (Cybersecurity — security management controls).
The new standard replaces CIP-003-8 and adds requirements for utilities to protect low-impact cyber resources (RD23-3).
Low-impact systems are defined as generation or transmission assets that pose a lower risk of disrupting grid operations if compromised. As a result, many of NERC’s critical infrastructure protection (CIP) standards, including CIP-003-8, only apply to cyber systems considered high- and/or medium-impact, leaving many low-impact systems unaddressed.
However, as FERC observed on Thursday, the Supply Chain Risk Assessment found that “the risk of a coordinated attack on multiple low impact assets with remote electronic access connectivity could result in an event with interconnection-wide impact on the bulk electric system.” In light of this possibility, the assessment called on the ERO to apply the CIP standards’ supply chain risk management requirements to low-impact assets with remote access connectivity.
The new standard accomplishes this objective with the addition of a new requirement, R.1.2.6, which will “require responsible entities to include the topic of ‘vendor electronic remote access security controls’ in their cybersecurity policies.” Another change will require entities with assets that vendors can access remotely to have the ability to detect and disable access, along with at least one method for detecting “malicious communications” through this channel.
According to the implementation plan proposed by NERC and approved by FERC, the new standard will take effect on the first day of the first calendar quarter that is 36 months after commission approval, or April 1, 2026. NERC explained the lengthy implementation period as necessary because of the large number of low-impact systems on the grid and the time needed by utilities “to procure and install equipment that may be subject to delays given high demand.” CIP-003-8 will be retired immediately prior to the new standard’s effective date.
In opening remarks at Thursday’s meeting, Commissioner James Danly called CIP-003-9 “a good first step” and Chair Willie Phillips said the new standard is “the latest product of our joint cybersecurity efforts with NERC and stakeholders in support of the reliable operation of the bulk power system.”
“You’ve heard me say this many times, and you’re going to hear me say it a lot more — we must continue to focus on cybersecurity and physical security, extreme weather events, and the rapidly changing resource mix,” Phillips said.
In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work toward assuring the reliability and security of the” electric grid.
The answer to the question of whether the U.S. can reliably decarbonize its electricity grid while electrifying most of its economy usually comes down to perspective — and how the question is framed.
For a media briefing on Monday, the U.S. Energy Association approached it with a sense of alarm and urgency as a “crisis ahead for electric utilities as electrification picks up.”
“The world’s greatest machine, the U.S. electricity supply system, will begin to sputter in a few years as more is asked of it than it can deliver with its present resources and constraints,” the USEA said in its invitation for the online event. “There is fear in the industry that it is heading toward a time when it can’t produce and deliver the amount of power the increasingly electrified world will need.”
Louis Finkel, NRECA | USEA
Speaking on a panel at the briefing, Louis Finkel, senior vice president of government relations at the National Rural Electric Cooperative Association (NRECA), acknowledged the opportunities in the country’s ongoing energy transition, but focused more on the “huge risk” now playing out in real-time.
Pointing to concerns raised by the National Academies of Science and NERC, Finkel said, the U.S. would need to increase generating capacity 170% “just to facilitate a surface transportation fleet transition … all while we have a disorderly retirement of baseload power.”
His frame of reference, he said, is rooted in NRECA’s 900 member cooperatives, which serve “92% of the persistent poverty counties in America,” where affordability and reliability are imperative.
Arguing for maintaining fossil fuel generation, Finkel said, “You need dispatchable power to keep the grid afloat, and you have to acknowledge that a megawatt of dispatchable power is not a megawatt of [intermittent] wind and of solar; the capacity factor is different.”
But Emily Fisher, general counsel at the Edison Electric Institute (EEI), countered that cross-industry conversations such as the USEA briefing should inspire optimism “that we can make it through this transition and provide customers resilient, clean power. I think we all know where we’re going, and there are going to be some challenges to getting there, but given the way that we operate and regulate the electric system in the U.S., it’s going to be a multistakeholder effort.”
Ron Schoff, EPRI | USEA
Ron Schoff, director of renewable energy and fleet enabling technologies at the Electric Power Research Institute (EPRI), said the problems of decarbonizing the grid while slashing greenhouse gas emissions are daunting but solvable.
EPRI expects U.S. renewable capacity will grow from 230 GW at present to 600 GW by 2030 as sales of electric vehicles, electric heat pumps and other electric appliances grow. Integrating those resources will “require system-level thinking to ensure that as we progress through the stages of decarbonization we are maintaining reliability, … affordability and … the level of service that our customers and people ultimately expect and, by the way, are increasingly dependent on as we start to shift to more electrification.”
John Di Stasio, Large Public Power Council | USEA
John Di Stasio, president of the Large Public Power Council, which represents the country’s 27 largest publicly owned utilities, said he was less pessimistic than “realistic and maybe pragmatic.” His topline concerns included the need for “permitting reform” and the decade-long lead times needed to build transmission or other large energy projects.
“We need a lot more coordination and harmonization to facilitate some of the aspirations that had been stated, and then … we really need every resource that we have, and that means natural gas,” Di Stasio said. He predicts ongoing complexity as the grid changes from an inertia-based system to a fully digital system “and trying to manage that from a compliance and reliability standpoint.
“We need to be optimistic, but [with] eyes wide open and making sure we’re covering all our bases as we go forward,” he said.
The End Mix
Federal and state policies have become key drivers for decarbonization and electrification, including President Biden’s goals of cutting U.S. GHG emissions 50 to 52% from 2005 levels by 2030 and decarbonizing the grid by 2035. The Infrastructure Investment and Jobs Act and Inflation Reduction Act contain a range of incentives for clean technologies, such as the IIJA’s $7.5 billion to build out a national network of 500,000 EV chargers and the IRA’s EV tax credits and heat pump rebates, all of which have set off a growing wave of private investment.
State-level policy is also pushing electrification forward, such as California’s Advanced Clean Cars II rule, which will require all new passenger cars, SUVs and light-duty pickup trucks sold in the state to be zero-emission vehicles by 2035. Eight additional states have either adopted the rule or are working toward adopting it.
At the same time, a range of industry voices, such as NRECA CEO Jim Matheson, have repeatedly said decarbonizing the grid by 2035 is unrealistic or not possible. RTOs and ISOs have said it could take years to upgrade and build out their systems to integrate the 1,400 GW of power capacity ― mostly solar, wind and storage sitting in their interconnection queues.
And while the need to update and streamline permitting processes in the U.S. has become a major bipartisan concern, bipartisan solutions remain elusive.
The catch, according to Schoff, is that solutions will have to evolve with technology as electrification and renewables on the grid increase.
“Do we have distribution transformers that are up to the task of everybody on my street having an EV with a fast charger on their wall or in their garage?” he said. An understanding of the regulatory and economic environments in which clean technologies will be deployed will also be essential, he said.
A mix of resources ― solar, wind, nuclear, hydro and natural gas ― will be critical to maintain reliability, but the amounts needed of each will also continue to change, Schoff said. “Whatever we’re going to end up [with] in 2050 or some future endpoint, it’s going to not look like that along the way.
“We’re going to have to progressively march our way through, and we have to manage risk at every point,” he said.
Todd Ramey, MISO | USEA
Todd Ramey, MISO’s senior vice president for markets and digital strategy, said the 171 GW of generation in the RTO’s interconnection queue — 95% of which is solar, wind and storage — would far exceed the RTO’s current 130 GW load, but putting those resources on the system would “drastically change the reliability characteristics of operating this fleet.”
“The only way to do that reliably is through extensive collaboration and coordination across participants, local regulators, state regulators and federal regulators, so that we have the information we need to make good choices, and it’s going to be a lot more dynamic than it’s ever been,” Ramey said.
The increasing frequency and severity of extreme weather events — like the winter storms in Texas in 2021 and in the Midwest and Mid-Atlantic in December 2022 — add another layer of complexity to the resilience challenge, Schoff said.
“You [need to know] whether wind turbines are able operate under certain circumstances, whether you have or need an enclosure around a natural gas plant, whether your coal pile may freeze, understanding the limitations potentially of natural gas,” he said.
Ramey agreed that “weather-dependent outages of fossil fuel-fired resources” have become a key issue, which will affect “the complexity of modeling and planning going forward. To the extent that there are resources that are not well-prepared to operate through extreme weather, that’s going to have effects in the way the resources are accredited,” he said.
Focus on Resource Attributes
Emily Fisher, EEI | USEA
EEI’s Fisher believes that a “broadly interconnected” system must be part of the solution for reliability and integrating renewables onto the grid.
“I actually find some of the distinctions between baseload and peaking a bit artificial in the current environment. Any resource can provide what is needed at any given moment in time, if it’s available,” she said.
“But a lot of that has to do with how broadly interconnected the system is. One of the true benefits of a broadly interconnected system is we’re able to rely on resources across a vast geography and that allows us to address some of the intermittency concerns” of renewables, Fisher said.
Both she and Di Stasio talked about the parallel evolution of utility planning processes. “You’re constantly in a planning process versus having a one-time plan and then you execute it over a decade,” Di Stasio said. He noted that his member utilities now plan with an eye to the attributes of resources and how they work together, rather than focusing on resource types.
“How do you get something that’s optimal versus just trying to do something that’s possible with one resource?” he said.
However, resource planning has its own challenges, Schoff said. “It’s so sensitive to the assumptions that are entered by the modelers for what the technologies are capable of and what they will cost. … We need to understand the system in which new assets will operate in and understand what they will have to be capable of.
“Will it be OK to build … wind and solar that are for the most part energy producers without a lot of dispatchability, or should we be including energy storage and some additional dispatchable technologies?” he said.
The decision might come down to interconnection requirements, market signals and technological advances, “but the system-level thinking about what that operation is going to look like needs to start informing the capital investment decisions for new projects as we go forward,” he said.
The role of demand-side management and the potential integration of distribution and transmission systems was also discussed.
While demand management occurs at the distribution level, Ramey said a key trend will be “the need to integrate load management into wholesale operations, blurring that current distinction between distribution and transmission.”
It may be a big leap for MISO and its members who rely on the RTO to operate the transmission side of their businesses, Ramey said, but “we’re all expecting the distribution system to be much more dynamic going forward. So, one of the challenges is to build on MISO’s current technology systems to start covering and penetrating and getting more information about the distribution system so we can optimize that interface.”
Schoff said more load management technologies will be needed. “The more loads you have that are controllable, the less pain each one of those loads will have to experience when you’re trying to manage the load on the grid,” he said. “We see a system coming forward that is much more dynamic on the demand and the supply side, and ultimately the grid in the middle is going to have to be able to manage that really effectively.”
WASHINGTON — The U.S. Energy Information Administration projects the nation will be able to cut energy-related CO2 emissions to 25 to 38% below 2005 levels by 2030, which falls short of President Biden’s target of a 50 to 52% reduction of all greenhouse gases.
But the agency’s 2023 Annual Energy Outlook says its analysis only looks at CO2, not the full range of GHGs, particularly methane.
Still, emissions reductions in the EIA’s 2023 reference case, not taking into account the full impact of the Inflation Reduction Act or other potential economic drivers, are 15% lower than last year’s estimates.
Speaking at a launch event on Thursday, EIA Administrator John DeCarolis cautioned that the outlook is based on federal policy and regulations as of November 2022, and that the full impact of the IRA has been difficult to model and integrate into the report’s forward projections.
By 2030, energy-related CO2 emissions fall 25 to 38% below 2005 levels | EIA
“We don’t explicitly include a representation of every IRA energy-related provision within the AEO,” he said, noting that “guidance might not be available on how a particular provision is enacted or how agencies will implement it.” Both industry and consumers are currently waiting for IRS guidance for many of the law’s tax credits and rebates.
In addition, DeCarolis said, “There are provisions that require significant model modifications that we simply weren’t able to complete this year.”
While acknowledging the implicit uncertainties of such modeling, DeCarolis also stressed that the report provides ranges of how different aspects of the transition could unfold based on several different scenarios modeled on high and low assumptions of economic growth and costs of oil, gas and zero-emission technology.
For example, the EIA sees electric generating capacity doubling by 2050 with solar, wind and storage accounting for most of the increase, but nuclear and natural gas remain more or less static. The range for solar runs from 22 to 56% of U.S. power production, EIA Assistant Administrator Angelina LaRose said.
Bonus tax credits in the IRA — for example, for projects paying prevailing wage and offering registered apprenticeships — could raise those figures to 39 to 59%, LaRose said.
Renewable growth will be driven by increasing electrification, she said, but “a higher share of renewables in the generation mix [will require] a higher total grid capacity requirement. This is owing to the currently lower capacity factors for solar and wind compared with coal, nuclear [or natural gas] combined cycle plants.”
Natural gas and storage will be needed to firm up intermittent resources, and “a small number of the relatively newer and more efficient coal power plants remain online in the United States due to their ability to provide cheap and dispatchable power to the grid,” LaRose said.
Increasing renewables on the grid may also drive higher levels of power curtailment, she said, with both higher gas prices and lower costs for renewables resulting in billions of kilowatt-hours of curtailment and a greater need for storage, both standalone and as part of hybrid projects combining solar and storage.
EV Uptake
The EIA does not expect the U.S. to hit Biden’s target for electric vehicles to reach 50% of new car sales by 2030. Even with high gasoline prices, the outlook estimates EVs making up 30% of sales by 2050. The reference case is even lower, less than 20%.
The EIA sees the IRA speeding EV adoption but expects sales to plateau after 2030, accounting for less than 20% of the market by 2050. | EIA
DeCarolis said the EIA’s modeling takes consumer choice into account. “When we all go to buy a vehicle, certainly the price matters a lot, but there’s more to those decisions,” he said. “So, at its core, it’s a consumer choice model. We do model technological learning, but it’s evolutionary.”
The EIA also did not factor in state policies like California’s Advanced Clean Cars II rule, which requires all new passenger vehicle sales in the state to be zero-emission by 2035. Four states have already adopted the rule, and four more are considering it, but DeCarolis said the potential impact was not integrated into the EIA’s models because the EPA has yet to approve the waiver for California’s rule.
He also expects the EV market to continue being limited to the luxury models automakers have introduced as they begin to build out their own electric fleets.
Natural Gas
Energy consumption for space heating will decline by 2050, but natural gas will remain the primary fuel for this end use in both the residential and commercial sectors, LaRose said.
Overall consumption is reduced because of “warmer winters, as well as population shifts to warmer and drier areas, higher efficiency heating equipment, as well as new building energy codes,” she said. But the growing market — and IRA rebates for heat pumps — will not offset ongoing use of natural gas, which will “continue to account for the largest share of energy consumption for space heating in the U.S. residential and commercial buildings.”
Older space heating will be replaced with higher-efficiency heat pumps and natural gas furnaces, she said.
The outlook also anticipates the U.S. will continue to be a net exporter of fossil fuels through 2050 and continue to rely on natural gas in both the industrial and electric power sectors. High economic growth and high adoption of zero-emission technologies could lead to “increased end-use demand, which results in more natural gas consumption,” the report says. “Higher costs for renewables make natural gas a more competitive option in that case, further increasing natural gas consumption in the electric power sector.”
The California Public Utilities Commission launched an investigation Thursday into the extremely high natural gas costs in California and much of the West this winter, when average prices at key trading hubs were five times higher than in the Eastern U.S. in December and January.
Utilities passed through the costs to ratepayers, many of whom were shocked when they saw their utility bills had doubled or tripled compared with last winter. The prolonged price spike also drove up the cost of gas-fired generation, adding $4 billion to California’s wholesale electricity costs in December and January, CAISOestimated in a report last month. (See Natural Gas Prices Add $4B to CAISO Electricity Costs.)
“This is one of the most pressing issues that ratepayers in California have faced this past winter,” CPUC President Alice Reynolds said before the unanimous vote to open the investigation. “It was an extraordinary spike in the price of wholesale natural gas, which led to steep increases in residential customer energy bills in January and February across the Western region.”
The investigation will look into the causes of the price spikes, their impact on customers, the possibility of recurrence, and the potential threats to gas and electric reliability this summer and beyond.
“The commission will also examine the utility communications to customers to determine whether they were sufficient or require modifications,” the order instituting the investigation said.
Giving ratepayers notice of high prices so they can reduce their natural gas use is one way to mitigate high prices, Commissioner John Reynolds said.
“If customers don’t even know about a price spike, they don’t really have an opportunity to change their behavior,” Reynolds said.
‘Anomalous Activities’?
The CPUC’s move followed Gov. Gavin Newsom’s request to FERC that it investigate natural gas prices in the West.
On Feb. 6, Newsom wrote to FERC Chair Willie Phillips, asking the federal regulator to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior or other anomalous activities are driving these ongoing elevated prices in the Western gas markets.”
FERC responded to Newsom in a letter this month saying it is “conducting surveillance to determine whether any market participants engaged in behavior that contributed to or took advantage of the high gas prices,” said Reynolds, Newsom’s former top energy adviser
Natural gas prices in California this winter were far above the national benchmark at the Henry Hub in Louisiana and much higher than last winter’s prices in California. | CPUC
“FERC possesses broad powers under the Natural Gas Act to investigate and penalize anti-competitive behavior in the interstate natural gas transportation pipelines under its jurisdiction,” she said.
The CPUC does not regulate natural gas prices, but it does have oversight of utilities, including Pacific Gas and Electric, Southern California Gas and San Diego Gas & Electric that pass on their costs to ratepayers without additional markups. The CPUC named 10 utilities and gas storage companies as respondents in the investigation.
Whether the CPUC or FERC will uncover evidence of wrongdoing remains uncertain.
In an analysis published in January, the U.S. Energy Information Administration said this winter’s price spikes were driven by below-normal temperatures in the West, pipeline constraints and low storage inventories, among other factors.
“The western region receives most of its supply from other parts of the United States and Canada,” the EIA wrote. “Net natural gas flows from Canada dropped by 4% in the first three weeks of December compared with the second half of November, and 9% less natural gas was delivered from the Rocky Mountains.”
The EIA also pointed to the impact on Southern California prices from gas pipeline maintenance in West Texas, which reduced flows into the Southwest.
On Feb. 7, the CPUC, CAISO and the California Energy Commission held a joint hearing to understand the factors that caused the cost increases. Market analysts and utility representatives who testified cited conditions such as an El Paso Natural Gas pipeline that exploded in Arizona in August 2021, impacting one supply line to California, and CPUC-imposed capacity limits at Southern California Gas’s Aliso Canyon underground storage facility, where a massive methane leak occurred in October 2015.
Newsom acknowledged in his letter to FERC’s Phillips that cold weather certainly “exacerbated” the gas price increases but lower-than-normal temperatures and other “known factors cannot explain the extent and longevity of the price spike,” he said. “It is clear that the root causes of these extraordinary prices warrant further examination.”
EPA on Wednesday announced the final details of its Good Neighbor Plan to slash emissions of smog-forming nitrogen oxides.
The rules will take effect this year and affect power plants and industrial facilities in the 23 states that contribute to unhealthy levels of ground-level ozone in neighboring downwind states, EPA said. It will resolve those states’ obligations under the 2015 National Ambient Air Quality Standards (NAAQS).
The plan includes a revised NOx allowance trading program with gradually decreasing emissions budgets. The 2027 NOx emissions budget for power plants in 22 states during the May 1-Sept. 30 “ozone season” will be 50% lower than the 2021 budget, resulting in significant public health benefits, EPA said.
Revisions to the trading program include features to promote consistent operation of emissions controls, annual recalibration of the emissions allowance bank and annual updates to the emissions budget to reflect changes in the generating fleet.
Also targeted in 20 states are NOx emissions from nine industries: natural gas pipelines; cement kilns; iron/steel/ferroalloy mills; glass furnaces; solid waste incinerators; metal ore mining; chemical manufacturing; petroleum/coal manufacturing; and pulp/paper/paperboard mills.
EPA projects a reduction of 70,000 tons of NOx emissions in 2026: 25,000 from power plants and 45,000 from industry. It also projects a reduction of 16 MMT of carbon dioxide, 29,000 tons of sulfur dioxide and 1,000 tons of fine particle emissions.
The rules drew cheers from environmental activists and warnings from the coal industry about the threat posed to electric resource adequacy and system reliability.
EPA projects that the final rule will result in an additional 14 GW of coal-fired power plant retirements by 2030, some of that through acceleration of shutdowns that had been scheduled after 2030.
EPA named 22 states with electric generating units (EGUs) linked to downwind air quality problems and said 10 of them will have to reduce their EGU NOx emission budgets by half or more by 2029, with the biggest percentage impacts on Utah (-84%) and Mississippi (-72%). Texas faces the biggest absolute cut, a 49% reduction totaling almost 19,500 tons. | EPA
The agency also expects the rules will incentivize retrofit of selective catalytic reduction emissions controls on 8 GW of coal power plants. And it expects the rule to accelerate buildout of renewable energy, primarily solar.
Each of the 23 states must submit a State Implementation Plan (SIP) to EPA within three years. If they submit an unacceptable SIP or miss the deadline, EPA will issue a Federal Implementation Plan within two years.
The states haven’t been very successful so far: On Jan. 31, EPA disapproved 19 states’ SIP submissions for the 2015 NAAQS and partially disapproved two other states’ submissions.
EPA said the Good Neighbor Plan provides enough lead time and flexibility that power plant operators can make the necessary changes at reasonable cost without impacting reliability.
But representatives of companies that mine and burn coal voiced concern Wednesday about the impact that the plan will have on the grid at a time when numerous states and the federal government are pushing for increased electrification and use of intermittent resources.
In a statement, the coal power industry group America’s Power said that the rule could “further increase the risks to grid reliability” that it has been warning about.
“Additional coal plant retirements are in stark contrast to the concerns that have been raised by the North American Electric Reliability Corp. and grid operators about the possibility of electricity shortages in many regions of the country caused largely by coal plant retirements,” CEO Michelle Bloodworth said. “Unfortunately, EPA has chosen to reject state plans that would have reduced emissions and avoided reliability problems and, instead, imposed its anti-coal bias on the states and the nation’s electricity supply.”
EPA said that it made several changes to the final rule to address reliability concerns raised by those commenting on the draft.
Among those is deferring “backstop” emission rate requirements for plants that do not have state-of-the-art controls until 2030, allowing power plant operators to “bank” allowances at a higher level through 2030 and establishing a “predictable minimum quantity of allowances available through 2029.”
“PJM worked extensively with other affected RTOs and EPA to address our reliability concerns with the rule as originally proposed,” it told RTO Insider via email. “We are encouraged by the changes that EPA has made and their indication of a willingness to develop various mechanisms to ensure the adequate availability of allowances to meet reliability needs. We intend to work closely with EPA and stakeholders to further the development of these reliability safety valve mechanisms to accompany the Good Neighbor Rule.”
The National Mining Association was not mollified.
“The nation’s grid regulators and operators have repeatedly warned EPA that its regulatory plans pose an ominous threat to reliability, and the EPA’s response is to paper over the problem with meaningless memorandums of understanding,” the group stated. “Intermittent renewable power additions will require a massive expansion of transmission infrastructure and energy storage — an effort that will take years to complete — in order to fill the gulf left by coal plant retirements. In fact, in 2022, as many as 40 planned coal plant retirements were postponed or scrapped largely due to acute grid reliability challenges where utilities and grid operators have made it clear closing plants would be reckless.”
“NERC has not done a specific analysis of the Good Neighbor Rule but recognizes that to assure reliability during the energy transformation, the pace of change must occur in an orderly and managed way, with flexibility to maintain generating units that are needed for reliability,” the ERO said via email. “NERC’s Long-Term Reliability Assessment examines the reliability implications of the changing resource mix, including the cumulative impacts of policies that are driving the transformation such as the Good Neighbor Rule.”
The rule is the latest in a long series of regulatory constraints on emissions from power plants, particularly those that burn coal. Already this year EPA has proposed tighter rules on wastewater discharge from coal plants and reaffirmed the Mercury and Air Toxic Standards for coal and oil plants. (See EPA Proposes Tighter Coal Plant Wastewater Regs and EPA Reaffirms Power Plant Mercury Regulations.)
The agency has framed the Good Neighbor Plan as a tool for public health and environmental justice. It said that in 2026 alone it expected the tighter emissions standards to prevent approximately 1,300 premature deaths, more than 2,300 hospital visits, 1.3 million asthma attacks, 430,000 school-day absences and 25,000 lost workdays.
It estimated the annual net benefit at $13 billion a year through 2042, not counting intangibles such as ecosystem improvements.
“We know air pollution doesn’t stop at the state line,” EPA Administrator Michael Regan said in a statement. “Today’s action will help our state partners meet stronger air quality health standards beyond borders, saving lives and improving public health in impacted communities across the United States.”
“Last summer, over 70,000 people shared their support for the Good Neighbor Plan, demanding fossil fuel power plants and industrial facilities that are polluting communities … comply with strict air quality standards,” said Leslie Fields, Sierra Club’s policy, advocacy and legal director. “We are pleased EPA is listening to the people it serves and finalizing this common-sense solution to dangerous interstate ozone pollution.”
The 23 states affected by the rule are:
industrial emissions only: California.
power plant emissions only: Alabama, Minnesota, Wisconsin.
both: Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia and West Virginia.
But the list may change. In a fact sheet, EPA said its updated modeling analysis showed that Arizona, Iowa, Kansas and New Mexico may be significantly contributing to ozone pollution in downwind states. It plans to undertake additional analysis to determine if they should be subject to Good Neighbor obligations.
The same updated modeling indicated Delaware is not significantly contributing to downwind pollution, so EPA withdrew its proposed Good Neighbor Plan for that state.
EPA is deferring action on Tennessee and Wyoming pending further review of the updated modeling.
