FERC on Friday approved MISO’s ability to abandon the only competitive transmission project it has ever assigned to its South region.
The commission’s order means the RTO can cancel its selected developer agreement with NextEra Energy Transmission (NEET) Midwest (NYSE: NEE) for the $115-million, 500-kV Hartburg-Sabine Junction project in East Texas. The grid operator recommended the project in 2017 (ER23-865).
MISO said that Texas’ 2019 right-of-first-refusal law prevented NEET Midwest from obtaining regulatory approval from the Texas Public Utility Commission to construct the project and meet a June 2023 in-service date. The grid operator said that after a fresh analysis of the project showed that it provided little value, it would not reassign the project to incumbent Entergy Texas. (See MISO Cancels Hartburg-Sabine Competitive Project.)
The project was intended to alleviate constraints in a load pocket straddling Texas and Louisiana.
NEET and the Southern Renewable Energy Association (SREA) attempted to save the project by lodging protests of the agreement’s cancellation with FERC. SREA has accused Entergy of strategically building generation near existing line routes to thwart projects that would open up Entergy’s service territory to outside generation supply. The nonprofit has said Entergy wants to preserve its load pockets. (See NextEra, SREA Protest Canceled MISO Project at FERC; SREA Criticizes Lack of MISO South Planning in FERC Tx Proceeding.)
SREA argued that MISO performed only a “limited” screening when it reexamined Hartburg-Sabine and did not conduct a more in-depth congestion analysis. The organization said the project could still be necessary to the MISO South system.
But the commission said MISO appropriately followed its tariff when it used schedule delays to trigger a project analysis and ultimately seek a dissolution of the developer agreement. FERC concluded it was “reasonable” for MISO to determine that NextEra was unable to complete the project.
“While NextEra and Southern Renewable disagree with MISO’s choice of outcome, we find that MISO appropriately exercised the discretion provided by its tariff in arriving at that outcome,” FERC said. “The issues NextEra and Southern Renewable raise do not provide a sufficient basis for us to find that MISO acted in a manner that is inconsistent with its tariff under the circumstances presented here.”
NEET maintained it was “optimistic” it could resume the project’s development following the 5th U.S. Circuit Court of Appeals ruling last year that Texas’ ROFR discriminates against nonincumbents in the portions of the state belonging to interstate transmission systems. Texas has since appealed the ruling to the Supreme Court. (See Texas Petitions SCOTUS to Review ROFR Ruling.)
“We disagree with NextEra’s argument that it is premature for MISO to find that NextEra is unable to complete Hartburg-Sabine given the status of Texas ROFR [l]aw litigation,” FERC said. “While it is true that the Fifth Circuit remanded the issue of the constitutionality of the Texas ROFR [l]aw under the Commerce Clause of the U.S. Constitution to the Western District, the Texas ROFR [l]aw is currently in effect.”
Entergy said it was appropriate for MISO to seek to terminate the developer agreement because the project can no longer deliver benefits.
In comments to FERC, Entergy said NextEra and SREA’s allegation that the utility is trying to stall outsider transmission projects or usurp those projects is untrue.
Entergy said its newly proposed, $1-billion Babel-Running Bear 500-kV project in East Texas is “completely different” from the Hartburg-Sabine project, counter to what NextEra alleged. Entergy gave notice to MISO that it intends to construct a substation and build a 150-mile 500-kV line to accommodate regional load growth and relieve the historically constrained Western Region load pocket. Unlike Hartburg-Sabine, a market efficiency project, the Babel-Running Bear project would be classified as a baseline reliability project and not be open to regional cost sharing.
The MISO stakeholder community has criticized Entergy for proposing billions of dollars of baseline reliability projects in the RTO’s South region in this year’s transmission-planning cycle. Stakeholders have pressed the grid operator to determine whether some of the projects could become more comprehensive, regionally allocated projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)
“Entergy believes that the transmission system should be planned and constructed to provide customers with reliable, reasonable cost electric service, including to accommodate the transition of a changing resource mix,” Entergy told FERC. “Among other things, transmission planning should consider generation solutions and local distribution facilities to ensure that the results of the planning process are efficient and will provide for a reliable grid.”
Rhode Island Energy said Friday it had hoped to receive more than one proposal in the state’s second offshore wind solicitation but recognizes the challenges facing the sector.
The company said it will now evaluate the joint Ørsted-Eversource proposal and decide in about three months whether to move forward with contract negotiations.
Future affordability of energy will be the central consideration in the process, it said.
The solicitation called for proposals for 600 to 1,000 MW of generation capacity, as specified in a 2022 Rhode Island law.
In response, Ørsted and Eversource proposed Revolution Wind 2, an 884-MW wind farm with projected economic benefits of $2 billion for the state. The two already are developing Revolution Wind 1, which would send 400 MW to Rhode Island and 304 MW to Connecticut.
Rhode Island Energy, a subsidiary of PPL (NYSE:PPL), is running the solicitation and would buy the power generated by a completed project.
Rhode Island Energy President Dave Bonenberger said in a news release Friday that under state law, any long-term power purchase agreements would need to be for 15 to 20 years.
“We’re committed to helping Rhode Island meet its leading clean energy goals and will carefully review Ørsted and Eversource’s joint proposal,” he said. “Our objective is to advance the clean energy transition while keeping energy affordable and reliable for our customers. This is the lens through which we will evaluate the proposal.”
Bonenberger also alluded to the financial and logistical challenges facing U.S. offshore wind developers.
“Although we had hoped to see more developers put forward additional proposals within this appeal, we also know there are a multitude of factors at play right now. As we move forward, our evaluation will consider future energy affordability and how this proposal meets the requirements of both the RFP and state law,” he said.
Headwinds
The first and so far only offshore wind farm completed in the U.S. generates a peak 30 MW off Block Island delivered to the Rhode Island coast. That is 0.1% of President Biden’s 30-GW goal for 2030.
Offshore wind energy is an important part of Rhode Island’s strategy to reach 100% renewable energy by 2033; multiple lease areas are clustered on the Outer Continental Shelf south and southeast of the state.
But as the Rhode Island RFP opened Oct. 14, offshore wind developers were wrestling with supply chain constraints, soaring interest rates and inflation.
Developers of two other New England OSW projects, Commonwealth Wind and South Coast Wind, have said the challenges that arose in 2022 made those projects untenable with the power purchase agreements that they had previously agreed on.
Commonwealth developer Avangrid wants to scrap its contracts and rebid; South Coast has not made that request, but also has not said its concerns have been satisfied.
Avangrid also said terms of the Park City Wind contract in Connecticut are untenable, and it has pushed back the in-service dates of Commonwealth and Park City in hopes that delaying start of construction would give manufacturers time to bring higher-output wind turbines to market.
Ørsted, meanwhile, is expecting a $365 million cost impairment on the Sunrise Wind 1 project in New York because its contracts were not locked in before economic headwinds arose in the nascent U.S. offshore wind industry.
And Eversource began looking for a buyer for its offshore wind assets in 2022 to free up capital.
Rhode Island’s second OSW solicitation closed March 13 with just the single Ørsted-Eversource proposal.
By contrast, when New York’s third OSW solicitation closed Jan. 26, it had drawn a robust response from six developers.
New York offered bidders the option of an inflation-adjustment mechanism.
FERC last week approved two Western utilities’ revisions to their transmission formula rate protocols in their response to a show-cause proceeding initiated last year.
The commission said Thursday that Public Service Company of Colorado (PSCo) (NASDAQ:XEL) and Idaho Power (NYSE:IDA) proposed revisions that are consistent with the standards established in a 2012 order regarding MISO transmission owners and would remedy the show-cause order’s concerns. It directed both companies to submit a compliance filing within 30 days of the orders (EL22-39 and EL22-37, respectively).
FERC opened the proceedings against the two utilities and three others last April under Section 206 of the Federal Power Act. It said the utilities did not appear to provide customers and regulators the ability to challenge rates resulting from the formulas. (See FERC Opens Probes on Western Tx Rate Protocols.)
The commission found that each of the five utilities’ protocols fell short on one or more of the following: “the scope of participation (i.e., who can participate in the information exchange); the transparency of the information exchange (i.e., what information is exchanged); and the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”
Neither PSCo, a subsidiary of Xcel Energy, nor Idaho Power refuted FERC’s findings.
PSCo said it would broaden the definition of interested parties to specifically identify the entities that can participate in its annual update process. It also proposed several other changes and said it would clarify that formal challenges by the parties should be filed pursuant to the annual informational filing docket’s protocols.
Idaho Power also said it would adopt MISO’s definition of interested parties that can participate in its annual update process. It proposed several other transparency-related revisions and said it would incorporate informal and formal challenge procedures that satisfy the MISO order’s requirements and provide a structured timeline that allows the review process to be completed before the next year’s posting.
In the MISO order, the commission ruled that the RTO’s protocols inappropriately limited who could participate in the review processes and directed it and TOs to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general.
Two of the other three show-cause proceedings are still active. FERC has not yet ruled on the PacifiCorp proceeding (EL22-38), but it granted Puget Sound Energy’s request for an extension (EL22-41).
The commission approved Public Service Company of New Mexico’s compliance filing in November (EL22-40).
Commission Accepts Black Hills Compliance
The commission also found that Black Hills Colorado Electric’s (NYSE:BKH) July 2022 compliance filing meets the requirements of FERC Order 864, which addresses excess and deficient accumulated deferred income taxes (ADIT) resulting from tax rate changes (ER22-2377).
FERC in June accepted tariff revisions for Black Hills’ transition from a stated rate to a transmission formula rate, suspending them until Sept. 1, 2022, subject to refund, and established hearing and settlement judge procedures. It also accepted the suggested ADIT worksheets, subject to refund and the compliance proceeding’s outcome.
Tri-State Generation and Transmission Association protested and moved to consolidate the proceedings, saying the worksheets lacked transparency and the level of detail required by Order 864. The commission rejected the argument, finding that the worksheets’ calculation steps “are shown clearly enough for an interested party to be able to verify that the calculations were done correctly.”
FERC dismissed Tri-State’s motion to consolidate the proceedings, accepting the compliance filing as just and reasonable without need for a trial-type evidentiary hearing.
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.”
