Search
`
November 4, 2024

Posted on

National Grid Backs out of Twin States Clean Energy Link Project

Despite support from the U.S. Department of Energy, National Grid has backed out of a major project to significantly increase the two-way transmission capacity between New England and Quebec.  

The news is a setback for efforts to increase bidirectional transmission connections between the regions, which could become increasingly important in coming decades as electricity demand increases and intermittent renewables proliferate. 

A partnership between National Grid and the nonprofit Citizens Energy Corp., the Twin States Clean Energy Link was proposed as a 1,200-MW transmission line through Vermont and New Hampshire expected to cost about $2 billion.  

The project was aimed at unlocking the potential of Canadian hydropower to fill in electricity gaps as intermittent renewable resources expand in New England. In this dynamic, New England would send power to Quebec during periods of renewable surpluses, while Quebec would send hydropower south during wind and solar lulls. (See Québec, New England See Shifting Role for Canadian Hydropower.) 

While two under-construction transmission projects between Quebec and the Northeast U.S. (New England Clean Energy Connect and Champlain Hudson Power Express) are set to provide consistent baseload power to New England for decades, Twin States was focused on hydropower’s balancing potential. 

“The cancellation of Twin States is a blow to New England’s decarbonization efforts,” said Emil Dimanchev, the co-author of a 2021 study that found increased bidirectional transmission capacity between regions would help reduce the timeline and cost of grid decarbonization. 

Dimanchev said the news indicates existing power market structures do not provide enough incentives for forward-looking transmission investments that would provide long-term benefits. 

He added that the project’s cancellation “is a symptom of the slow pace of wind build-out in New England. It shows us that there is a greater need for planning transmission and generation investments in a more coordinated fashion.” 

National Grid declined to elaborate beyond a brief statement on the reasons for the cancellation. 

“National Grid has determined that the project is not viable at this time,” the company wrote. “We will continue to pursue paths to building much-needed transmission capacity for the region and for our customers and communities.” 

“While we respect National Grid’s decision to suspend development of the Twin States Clean Energy Link,” Citizens Energy President Joseph Kennedy III wrote in a statement, “we are disappointed to lose this vital opportunity to help New England meet its green energy goals.” 

In October, DOE announced its intention to serve as an anchor off-taker for the project by purchasing up to 50% of the line’s capacity to reduce development risk. (See DOE to Sign up as Off-taker for 3 Transmission Projects.)  

“It’s discouraging that a project that had such significant Department of Energy support could not make it across the finish line,” said Joe LaRusso of the Acadia Center. “Broader U.S.-Canadian cooperation and coordination is still needed, because in the future we are going to have to have a grid that spans the entire Northeast Power Coordinating Council reliability zone.” 

New Hampshire officials expressed disappointment in response to the news. Donald Kreis, New Hampshire’s consumer advocate, called using Canadian hydropower to balance renewables an “intriguing idea,” but said the project’s cancellation shows the lack of a business case for new transmission lines between New England and Quebec.  

“There is a need for more transmission capacity in New England, [but] the merchant model — at least as premised on moving more power out of Canada — seems to be unraveling as a viable proposition,” Kreis said.  

In an op-ed written prior to the project’s cancellation, Kreis expressed concern about a legislative proposal for New Hampshire to contract up to 240 MW of the line’s capacity. Kreis said other states should step up to help fund the project. 

“New Hampshire represents, at most, around 10 percent of New England’s electric consumption,” Kreis wrote. “If we are going to promise to fund a 1,200-megawatt transmission project intended to benefit the whole region, our fair share is, at most, 120 megawatts.” 

Hydro-Quebec, which had not signed a commercial agreement related to the project, expressed its disappointment with the cancellation while reiterating the company sees significant potential in increased bidirectional electricity exchange. 

Serge Abergel, COO of Hydro-Quebec’s U.S. operations, told RTO Insider the company will continue studying the potential of new two-way transmission projects. 

As the deployment of intermittent renewables accelerates, “there’s no doubt that the future has some sort of bidirectional agreement in store for Quebec and its neighbors,” Abergel said, while emphasizing that the Twin States project was an early-stage attempt to build on hydropower’s balancing potential. 

“We just don’t have enough information to convince people yet, nor do we have enough information to say this is not interesting,” Abergel added. “Our work goes on.” 

Posted on

RTO, Day-ahead Choice Closely Linked, Nev. Effort Shows

NV Energy is aiming to bring a proposal to Nevada regulators by the end of the year for joining a day-ahead market, but what process regulators will use to evaluate that request is still very much up in the air. 

“It would be good for our internal purposes and potentially for others in the West, because a lot of the utilities in the West feel that their market decisions are based in not insignificant part on what their neighbors are doing,” David Rubin, NV Energy’s federal energy policy director, said during a March 4 workshop. “There are clearly relationships, for example, between Nevada and Idaho.” 

Rubin said that by filing a proposal with the Public Utilities Commission of Nevada (PUCN) by the end of the year, NV Energy could let others know the company’s intentions before they have to decide on making a “fairly significant” financial commitment for the next phase of SPP’s Markets+. CAISO’s Extended Day-Ahead Market (EDAM) and Markets+ are competing to attract day-ahead market participants. 

Rubin said the interrelationship among utilities in the West when it comes to day-ahead markets is underscored by recent studies, including a just-released report from Brattle Group, which found greater economic benefits for NV Energy if the utility went with EDAM rather than Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

PUCN Investigation

Rubin’s comments came during a PUCN workshop conducted by Commissioner Tammy Cordova, the presiding officer in an investigation of regional market activities in the West. In addition, state law requires NV Energy to join an RTO by 2030, and the investigation will look into how the PUCN will oversee that process. 

NV Energy and other interested parties filed written comments on the matter ahead of the workshop. (See Nev. Regulators to Weigh Approaches to RTO Membership.) 

Some commenters said the commission could consider an NV Energy proposal to join a day-ahead market through its energy supply plan (ESP) — a process that was used in 2014 when the utility decided to join CAISO’s Western Energy Imbalance Market (WEIM). But joining an RTO would be more complex, and new rules from the PUCN might be needed, some said. 

During the workshop, Shelly Cassity of the PUCN’s regulatory operations staff said joining a day-ahead market is “a much bigger step” than becoming a WEIM member. And the 135-day timeline for evaluating an ESP is relatively short, she said. 

“We think that the ESP process may not be the ideal route,” Cassity said. “We think regulations may be necessary.” 

Similar Issues in Colorado

In considering day-ahead market and RTO issues, the PUCN may look to Colorado, where the legislature in 2021 passed a bill requiring utilities to join an RTO by 2030, similar to Nevada’s Senate Bill 448. The Colorado Public Utilities Commission has been working on rules to guide the process of joining a day-ahead market or RTO and recently released draft regulations. 

During the PUCN workshop, Brian Turner, a director at Advanced Energy United, said the Colorado PUC is looking at splitting the decision about utilities joining an RTO into two parts: whether the RTO meets criteria laid out in statute and then whether joining an RTO is in the public interest. 

The definition of an RTO in Nevada’s SB 448 includes requirements that the organization be FERC approved, improve reliability in the state and have a governance structure that’s independent of transmission users. 

Cordova indicated she was open to considering Colorado’s approach. 

“As we keep telling people, this is Nevada, it’s not Colorado,” she said. “But I am also a big fan of not creating a wheel that I didn’t have to invent.” 

PUCN’s March 4 workshop is expected to be followed by additional workshops, including at least one focused on the Brattle Group findings and other studies of potential market benefits. 

Cordova said she’d issue a procedural order laying out a timeline for the proceedings in the next week or so.

Posted on

Global CO2 Emissions Hit New High, Could Have Been Higher

The International Energy Agency reports that worldwide CO2 emissions hit a record in 2023 but would have climbed even higher without the rapid adoption of clean technology.  

The year-over-year emissions growth in 2023 was not as great as in 2022, IEA said, even as the growth in energy demand accelerated. Over the past five years, IEA added, clean energy generation capacity increased at twice the rate of fossil generation. 

The analyses come in the 2023 edition of IEA’s annual CO2 emissions update and in the inaugural edition of its new “Clean Energy Market Monitor.” 

Combined, the two reports attach new statistics and details to trends that have been observed in recent years. Takeaways include: 

    • Global CO2 emissions increased by 410 million tons in 2023, reaching 37.4 billion tons; this compares with a 490-million-ton increase in 2022. 
    • Advanced economies saw a record decline of emissions in 2023 as low-emitting resources accounted for half of their electric generation; their emissions dropped to a 50-year low, and their use of coal dropped to a 120-year low. 
    • This is because clean energy continues to be largely concentrated in advanced economies and China; in 2023, they accounted for 90% of new solar and wind generation and 95% of electric vehicle sales. 
    • Clean energy has become a major industrial sector and an important part of the world economy; investment has been growing 10% annually and totaled $1.8 trillion in 2023 alone. 
    • China continued its rapid buildout of clean-energy technology in 2023, adding 64% more solar capacity than the rest of the world combined and leading every other metric except nuclear. But China also ratcheted up fossil fuel consumption in 2023 as it continued its post-pandemic recovery and saw hydropower generation decrease by 125 TWh. The overall emissions increase was estimated at 565 million tons. 
    • The United States decreased CO2 emissions from energy combustion by 4.1%, even as its economy grew 2.5% and hydropower and wind power output declined; the coal-to-gas transition was the largest factor. 
    • By contrast, coal demand in emerging and developing economies was the largest driver in the worldwide increase in CO2 emissions. 
    • Extreme drought curtailed hydropower output in multiple regions in 2023; the use of fossil fuel as a replacement accounted for more than 40% of the worldwide increase in emissions. 
    • In countries with large energy demand for indoor temperature control, the 2023 heating season was much milder than 2022, but the 2023 cooling season was not much hotter, yielding a 120-million-ton net year-over-year reduction in emissions. 
    • Heat pump sales dropped marginally in 2023, which is attributed to consumer hesitance on large purchases. 
    • Hydrogen electrolyzer capacity increased 360% in 2023, but that was from a low starting point. 

In a news release accounting the reports, IEA Executive Director Fatih Birol said: “The clean energy transition has undergone a series of stress tests in the last five years — and it has demonstrated its resilience. A pandemic, an energy crisis and geopolitical instability all had the potential to derail efforts to build cleaner and more secure energy systems. The clean energy transition is continuing apace and reining in emissions — even with global energy demand growing more strongly in 2023 than in 2022.” 

The International Energy Agency reports the largest increase in renewable energy and the largest amount of avoided emissions was in the solar sector. | IEA

But the transition needs to extend beyond the handful of leading economies, Birol added: “We need far greater efforts to enable emerging and developing economies to ramp up clean energy investment.” 

Statistics in the “CO2 Emissions in 2023” report are based on IEA analysis of energy, economic and weather data about carbon dioxide emissions from energy combustion and industrial processes. The “Clean Energy Market Monitor” relies on data from national sources and industry associations. 

Posted on

NV Energy to Reap More from EDAM than Markets+, Report Shows

NV Energy would gain significantly more economic benefits from participating in CAISO’s Extended Day-Ahead Market (EDAM) than SPP’s Markets+, new analysis from the Brattle Group shows. 

The analysis was included in slides referenced — but not presented — by the utility during an RTO markets workshop hosted by the Public Utilities Commission of Nevada on March 4. An NV Energy official said the utility will review the findings with the commission at a future workshop, the date for which has not been determined. (See Nev. Commission to Tackle Rules for RTO Membership.) 

The Brattle study looks at financial outcomes for NV Energy based on five market footprints, with benefits measured against a business-as-usual scenario that assumes membership in CAISO’s Western Energy Imbalance Market remains unchanged. 

Brattle said it conducted the simulations underpinning the study using a nodal production cost model of the Western Interconnection “with added market functionality, such as contract-path transmission.”  

The study looks at performance in 2032, “which aims to reflect the first decade of markets operations, representing both an intermediate year in the near future and a year with reasonably high renewable penetration in the” Western Interconnection, Brattle said. 

In the “Bookend EDAM” scenario, which assumes nearly all utilities in the Western Interconnection participate in the EDAM, NV Energy would gain about $62 million in annual benefits from higher transfer revenue and lower annual production costs (APC). In that scenario, the utility would facilitate a sharply increased amount of trade between with Southwest and California, while also helping to transfer more low-cost generation from California and the Southwest to the PacifiCorp-East and Idaho Power balancing authority areas. 

NV Energy would reap the most benefits — $149 million — from the “Middle View 1” scenario, in which EDAM contains all entities that already have announced for that market, plus Seattle City Light, Portland General Electric, Idaho Power and NV Energy. In that scenario, the Bonneville Power Administration and most of the Northwest’s publicly owned utilities, Puget Sound Energy, and all Arizona BAAs join Markets+. NV Energy sees fewer transfers here than in Bookend EDAM, but it also has less competition for low-cost renewable generation, reducing its purchase costs by about $50 million. 

The “Bookend Markets+” scenario assumes NV Energy is participating in Markets+ along with all Northwest and Southwest (including New Mexico) entities, putting a seam between PacifiCorp-East and CAISO and PacifiCorp-West. In that scenario, NV Energy earns $16 million in benefits based on transfer revenues and lower APC but loses access to low-cost generation in the EDAM. 

The “Middle View 3” scenario keeps NV Energy in Markets+ but removes the Avista, NorthWestern Energy, El Paso Electric and PNM BAAs, reducing the Nevada utility’s annual benefits to $9 million based on lost revenue and increased purchase costs in the smaller footprint. 

But NV Energy would incur net losses from participating in Markets+ in “Middle View 2,” which assumes Idaho Power joins EDAM, “cutting off a major pathway” between the Southwest and Pacific Northwest, with flows between areas restricted to just 200 MW. In that scenario, energy flows with Idaho decline by about 3,000 GWh a year.  

Brattle’s analysis examined outcomes from five different market scenarios in the West. | Brattle Group

Takeaways

Among Brattle’s suggested “key takeaways” from the study: NV Energy’s estimated benefits would be highest in the EDAM, “largely due to the opportunity to sell additional generation at higher prices and buy at excess solar at lower prices.”  

The study also found that the scale of NV Energy’s benefits is heavily influenced by the market footprint’s shape “due to its large amount of transfer capability and centrality” in the Western Interconnection.  

“NVE benefits tend to be higher when it is central to the market and facilitates transfers within the market (e.g., in Bookend M+ case, in which NVE facilitates transfers between the PNW and SW; or Bookend EDAM case, in which NVE facilitates transfers between CAISO and the SW),” Brattle said. 

Conversely, benefits decline for the utility when it sits on the margin of Markets+, the analysis found. 

Brattle noted also that NV Energy would suffer negative impacts from shifting out of the WEIM and into Markets+ “as it loses access to excess renewable supply from CAISO in real time and sees lower prices for [real-time] sales.”   

Posted on

ACORE Panel: IRA is Safe, but Trump Could Decimate DOE

WASHINGTON, D.C. ― The best way to defend the clean energy incentives in the Inflation Reduction Act could be to stop mentioning the law and focus on its benefits, a trio of speakers told the American Council on Renewable Energy (ACORE) Policy Forum on Feb. 29. 

Melissa Burnison, vice president of federal legislative affairs at Berkshire Hathaway Energy, called for a refocus on areas of bipartisan agreement: “Our transition to a smart grid and … technologies that make the grid more efficient, that also increase their ability to carry more power [and] the responsiveness of the grid.” 

“Everybody likes jobs and … everybody likes clean air and clean water for their kids, too, and for their communities,” said Sarah Hunt, president of the Joseph Rainey Center for Public Policy, a conservative-leaning D.C. think tank. “So, if you can talk about the benefits that your business has received from this policy, from this legislation, and how that translates and passes on to your customers and communities with which you engage … that’s the best way to go about it.” 

In a rare all-female panel, Burnison, Hunt and Kelly Speakes-Backman, executive vice president for public affairs at power and transmission developer Invenergy, debated the way forward for the IRA and the future of U.S. clean energy policy should Republicans win both Congress and the White House in November.  

Introducing the panel, moderator Jayni Hein, co-chair of the carbon management and climate mitigation group at Covington & Burling, spoke first of the benefits of the law, with money and projects flowing to both red and blue states. “But despite these widely shared benefits, we’re at a really uncertain point,” Hein said.  

“The Department of Treasury is in the midst of finalizing some very important rules and guidance,” such as direct pay and transferability of tax credits, along with updated guidance on bonus credits for energy communities and domestic content. 

With the election hanging over such decisions, “the best defense is offense,” Hein said. 

But the panelists mostly stuck with an emerging consensus ― also heard from other speakers at the forum ― that the economic benefits the IRA is creating will make it hard to repeal. (See Whitehouse: Best Defense for IRA Is Funding, Building More Projects.) 

Burnison described her view as “optimistic and grounded.”  

“Bipartisan benefits from the IRA, from tax policy [are] something that ― even from the most conservative congressional members, we’ve heard ― we’re not going to see a wholesale repeal of the IRA,” she said.  

“First of all, it’s probably not possible, and second of all, it doesn’t make sense for their constituents.”  

Hunt argued that even if Donald Trump returns to the White House and Republicans win control of both houses of Congress, “much of [the] IRA, much of the federal investment in clean energy [research and development], especially all-of-the-above, technology-neutral [incentives], are going to be fine.” 

“I don’t think that President Trump and a Republican Congress are going to care a whole lot about the federal budget being too big,” she said, pointing to Republican spending between 2017 and 2020. 

Going further, Hunt attempted to reframe the IRA as a “good Republican energy bill,” which included many provisions worked out in “bipartisan activity or even Republican offices.” The law has become politicized because the Democrats chose to pass it through the budget reconciliation process, rather than taking longer and pushing for a bipartisan bill, she said. 

In calling for a return of manufacturing to the U.S., she said, Trump “socialized industrial policy … and it allowed for the IRA … for that conversation to take root and happen.” 

Hunt said she sees support for the IRA coming from officials who worked at the Energy and Interior departments during the former administration and are now in leading positions at energy companies and advocacy groups.  

Burnison was at DOE when former Texas Gov. Rick Perry was secretary of energy. Both she and Hunt identified themselves as Republicans who embrace clean energy and favor a technology-neutral approach. 

Republicans Now Recruiting

Although the IRA’s clean energy incentives are likely safe, a second Trump administration will likely prioritize a fundamental shift in energy policy, from decarbonization and climate to energy and national security, the panelists said.  

Speakes-Backman sees such a shift resulting in budget cuts at DOE, which could affect staffing and policy.  

Recalling her time at DOE as principal deputy assistant secretary in the Office of Energy Efficiency and Renewable Energy from 2021 to 2022, she said implementing the IRA has been an enormous job for the department after its staffing was cut by Trump. 

Her own office had “the lowest rate of staff to dollars ever in the history since 1977 … with dozens of studies that were [postponed] ― on transmission, on hydropower, certainly on solar and renewables,” Speakes-Backman said. “There were quite a few things that were stalled out across the entirety of DOE.” 

Even if Republicans in Congress are “not going to be as focused on spending, they certainly will be focused on spending on administrative agencies that are pushing toward clean energy,” she said. “There is going to administrative slowdown,” which could also slow efforts to pass legislation to streamline permitting.  

The agencies working on clean energy ― DOE, Interior and EPA ― “are going to be decimated,” Speakes-Backman said. 

Neither Hunt nor Burnison saw any major threat in a Republican refocusing of energy policy.  

That approach will change priorities around “how we look at things like solar and what we’re importing,” Burnison said, referring to Chinese dominance in the refining and processing of critical minerals for solar panels and electric vehicles. “What does that timeline look like in order to begin to phase out some of those imports and to begin to rebuild our domestic manufacturing capability and reliability?” 

Responding to Speakes-Backman’s concerns over cuts to DOE, Hunt talked up current efforts, being led by the Heritage Foundation, to recruit and train new staff for federal agencies, who will be “ready to go on Day 1” of a new administration. At the same time, she discounted Project 2025, the foundation’s 920-page blueprint for the next Republican administration.  

The section on DOE, authored by former FERC Commissioner Bernard McNamee, calls for the department to be renamed the Department of Energy Security and Advanced Science, with a narrowed focus on energy and national security, “cutting-edge fundamental advanced science” and developing new nuclear weapons. 

While Hunt said the report should be read “with a grain of salt,” the personnel recruitment and training program is part of Project 2025 and led by three former Trump officials.  

Good Business

Hunt said the electric industry’s support for the IRA will protect it from being repealed by Trump.  

Burnison said Berkshire Hathaway and other energy companies are looking for the finalization of guidelines on the law’s tax credits and other rules, which will provide the regulatory certainty the industry has been waiting for.  

“Are we expanding regulatory authorities? Are we contracting some of those? Where are the regulatory authorities moving to or even over to DOE? … Are we changing what those look like?” Burnison asked. With large energy or transmission projects taking five to 10 years or longer to permit and build, she sees a mismatch between IRA incentives and long-term business planning.  

Speakes-Backman is waiting for the final guidance on tax credits for green hydrogen “as it relates to the ramp to hourly accounting” — matching the zero-emission energy used to produce clean hydrogen on a 24-7 basis versus the annual accounting widely used now.  

“I think we all want to get to an hourly, fully clean hydrogen, but as we’re standing up the industry, there is a pace,” requiring a phased-in approach, she said. 

Whoever wins the White House, Senate or House must understand “that clean energy is good business,” she said. “Whether that be in renewables, whether that be in natural gas to help peaking, whether it be transmission, whether it be energy storage, it is good business for this country.” 

Posted on

NJ Panel Backs Bill to Increase Distribution Capacity for Renewables

New Jersey’s Senate Environment and Energy Committee unanimously approved a bill March 4 requiring electric utilities to develop plans for upgrading their distribution infrastructure to increase renewable generation capacity. 

The bill would give the state’s four utilities 90 days to draft and submit a plan to the Board of Public Utilities, with a goal of reopening “many of the state’s electric distribution circuits that have been closed to any additional renewable energy installations, or restricted to 100 kilowatts or less of remaining circuit capacity” (S2816). The bill gives the BPU 30 days to approve or modify each plan; utilities would be required to schedule the work “at the earliest date possible.” 

The committee also approved bills to restrict new fossil fuel generation and divest oil and gas investments on party-line votes at its March 4 meeting. 

Committee Chair Bob Smith (D), co-sponsor of the distribution upgrade bill, said it would “allow us to get more solar into New Jersey residential homes” at a relatively modest cost. 

Still, he added, “this bill doesn’t say you must do” the upgrades, but instead requires the utility to submit a plan to the BPU, which then decides how to proceed.  

“What we’re saying by the bill is ‘Let’s get it done,’” Smith told the committee. 

Many Rejections

The bill, which the committee backed 5-0, comes as New Jersey, like other states, is struggling to connect a surge of renewable energy projects to the grid in a timely fashion.  

Solar developers say the problem is particularly egregious in Atlantic City Electric’s territory in South Jersey, where connections can take months or years. (See Solar Developers: New Jersey’s Aging Grid Can’t Accept New Projects.) 

“There’s a lot of rejections coming down,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, which proposed the bill to Smith. Developers are going into the utility with a planned solar rooftop or ground mount project “and the utility says, ‘You can’t connect there; we can’t do it,’” he said. 

“It’s a first step, taking the worst problem first,” he said of the bill, adding he expects the industry to be addressing interconnection problems for a decade or more. In this case, the bill focuses on improving customers’ ability to connect to the distribution system, rather than addressing the transmission system.  

The bill would require each utility plan to address issues such as how to permit the flow of electricity from the distribution system through an electrical substation to the transmission system, and to “include, activate and utilize all available inverter technology.” The bill also requires the plans to include any inverters needed to implement energy storage systems. 

Brian O. Lipman, director of the state Division of Rate Counsel, urged the BPU in a March 1 letter not to back the legislation. He said the plans required by the bill would be too complicated to be properly evaluated in the period allowed and would “very likely cause ratepayers to grossly overpay for imprudent and unreasonable costs.” 

Addressing the committee March 4, Lipman said the legislation should give the utilities more time to craft a plan and the BPU more time to review it. The BPU also should be allowed to reject a utility’s plan, not just approve or modify it, he said. 

“Part of the process at the BPU is vetting out the ones that are good, making sure that those are done, and making sure the ones that are not so good are actually taken off the table,” he said. 

Smith said he will amend the legislation to add a denial option and provide longer timelines. 

Constitutional Amendment

The Democrat-controlled committee also backed a bill that would seek to amend the state constitution to prohibit construction of new fossil fuel power plants, except for peaker units, on a 3-2 vote (SCR11). If the legislation is enacted, the issue would go to voters to decide whether to back the prohibition. 

The bill would prohibit the state from granting any approvals for the construction of a plant “that produces electric power, in whole or in part, from the combustion of coal, natural gas, oil or petroleum products.” The legislation also prevents anyone from building such a plant. 

“This bill is an attempt to be reasonable about our fossil fuel electric power generation,” said Smith, a bill co-sponsor. Instead of saying, “Shut the switch off now,” he said, the bill allows fossil fuel plant to continue generating until “the end of the useful life.”  

The committee first discussed the bill at a Feb. 5 hearing to solicit public opinion without a vote. After receiving comments that relying on renewable energy without peaker plants would threaten reliability, Smith revised the legislation to allow for the construction of new peaker plants. 

Even so, Dennis Hart, executive director of the Chemistry Council of New Jersey, which represents more than 60 manufacturers, said the bill could threaten the energy sources on which his members rely. He said they already pay 50% more for energy than manufacturers in other parts of the company. 

The state’s nuclear plants, which produce about 30% of the state’s energy, are already 60 years old, and their future performance can’t be assumed, he said, adding later that the state needs a “diversity” of energy sources. 

“We need a reliable, cost-effective source of electricity,” he said. “And I think it’s shortsighted to cut out fossil fuel generation.”  

Misinformation

Environmental groups also had concerns about the bill. David Pringle, speaking against the bill on behalf of Empower New Jersey, an environmental group, said the focus of the amended bill was too narrow, and would only prevent the construction of “new gas plants of a very large nature.” Those plants, he added, are not likely to be built anyway because they are no longer economically feasible. 

Anjuli Ramos-Busot, the director of the New Jersey chapter of the Sierra Club, also opposed the bill, saying the state already has enough peaker plants to support renewable energy, and any attempt to update them would be limited by the state’s Environmental Justice law, which took effect in 2023. 

She said the organization is also worried that taking the issue to a voter campaign would unleash a flood of misinformation about clean energy. 

“We’ve seen a decrease — a slight decrease — in support for offshore wind, because of misinformation, because of the fossil fuel industry pouring in millions and millions of dollars to misinform the public,” she said. “Our fear is that we won’t be able to compete. Sierra Club is an environmental nonprofit; we don’t have millions of dollars to spend in a campaign to educate properly the public and deny the misinformation.” 

Before moving the bill for a vote, Smith said “all the experts that I’ve talked to feel that you got to have some peakers,” suggesting they should be permitted under the bill. He added that he is not afraid of triggering a heated campaign.  

“I have a lot of faith in the voters of New Jersey,” he said. “I think they can figure it out.” 

Investment Pressure

The committee also backed, by a 3-2 partisan-line vote, a second bill that had been discussed on Feb. 5 but not voted upon so that public input could be evaluated. The bill, S198, sponsored by Smith, would prohibit the state from investing “in any stock, debt, or other security of any company, or any subsidiary, affiliate, or parent of any company, that is among the 200 largest publicly traded fossil fuel companies, as established by carbon content in the companies’ proven oil, gas, and coal reserves.” 

Ray Cantor, senior lobbyist for the New Jersey Business and Industry Association, said that given that the state’s pension fund is underfunded by $80 billion, “it’s bad policy to use the pension to try and drive public policy.”  

But Smith said that the impact of climate change is too great to continue supporting fossil fuel companies. 

“My hope is that if they get called out by enough state governments, the federal government, that maybe they’ll change what they do,” he said. 

Posted on

FERC Rejects Complaints from IMM, W.Va. PSC Arguing for Access to PJM Liaison Committee

FERC has denied a pair of complaints against PJM from the Public Service Commission of West Virginia and the RTO’s Independent Market Monitor arguing that denying them access to the RTO’s Liaison Committee violates its governing documents and FERC orders on transparency and board independence (EL23-45, EL23-50). 

The PSC complaint, filed March 8, 2023, argued that language in PJM’s Operating Agreement (OA) detailing the structure of standing committees includes the LC and mandates that nonvoting ex officio members, such as state utility commissions, be permitted to attend. Excluding them from the room while representatives of the five PJM member sectors meet with the RTO’s Board of Managers prevents PSC staff from fully understanding PJM’s decision-making process and may enable FERC-regulated utilities to advocate for market rules that are not in the state’s interest before the board, the regulator argued. (See W.Va. PSC Files Complaint over PJM Meeting Policy.) 

The Monitor stated that the LC often discusses market issues that pertain to its monitoring role. Tariff Attachment M — which details the Monitor’s role in PJM — grants it access to the full stakeholder process, including working group and committee meetings, when it “deems appropriate or necessary to perform its function.” The Monitor’s complaint was filed on March 24, 2023. 

“Excluding the Market Monitor from stakeholder meetings compromises the ability of the Market Monitor to perform its function by depriving it of information exchanged in such meetings and the opportunity to state its independent views. The Market Monitor cannot effectively perform its function when it is excluded from stakeholder meetings. In addition, the Market Monitor has a direct interest in hearing communications and responding to communications from a member or members to the Board that concern the Market Monitor’s performance of the market monitoring function and the terms and conditions of its retention by PJM,” the Monitor’s complaint said. 

The commission’s March 1 order rejected the Monitor’s complaint, stating it had not demonstrated the LC is a part of the stakeholder process under Attachment M, nor established it is part of the Board of Managers’ decision-making process requiring the Monitor’s access. The order says the Monitor has sufficient access to the board through multiple stakeholder process meetings and direct meetings with the board that are closed to stakeholders. 

The Organization of PJM States Inc. (OPSI) submitted comments supporting the Monitor’s complaint, saying state regulators rely on the Monitor’s analysis when considering the effects RTO decisions could have on their rates. By preventing the Monitor from participating in the LC —which it argued is among the most important committees where stakeholders meet with PJM’s Board of Managers — OPSI said the Monitor’s ability to provide state utility commissions with fully informed opinions is inhibited. 

State commissions, FERC staff, the Monitor and OPSI had been permitted to attend the LC until September 2018, when the Members Committee voted to enforce a provision of the LC’s charter limiting attendance to PJM members and its board. (See PJM Stakeholders Table WVa PSC Attendance at Liaison Committee.) 

In rejecting the West Virginia complaint, the commission cited PJM’s argument that the LC is not a standing committee under the OA but instead was formed through a joint effort of the Board of Managers and MC, putting it outside the stakeholder process and not mandating the attendance of state commissions or the Monitor. FERC also said state commissions have adequate access to the board through meetings with PJM through OPSI and at stakeholder meetings with board participation, such as the Members Committee. 

Responding to the PSC’s complaint, PJM compared the LC’s formation to the memorandum of understanding signed with OPSI to hold regular meetings with the Board of Managers without the participation of other stakeholders. 

Transmission owners and the PJM Power Providers (P3) Group argued that keeping the committee closed is appropriate to allow market participants to have candid conversations with the Board of Managers, while the West Virginia commission argued it violates the transparency and board independence provisions of FERC Orders 2000 and 719. The Monitor argued that positions made by PJM members before the board should stand regardless of who is in attendance. 

P3 also argued that allowing the participation of consumer advocates, who are ex officio members with voting rights at the Members Committee, but not state committees, is appropriate because the LC provides an opportunity for voting members to express their views on issues they may be voting on before the board. 

Christie Dissents

Commissioner Mark Christie dissented from the order’s rejection of the Monitor’s complaint, arguing that the majority had focused too much on Attachment M and not considered its relation to the Monitor’s role in PJM, causing it to “miss the forest for the trees.” He argued that even if no votes are taken at the LC, meeting to express views on issues faced by PJM and its members is one in a series of actions that culminates in board decisions. Christie concurred with the order’s stance on the West Virginia complaint and stated he believes the result is correct but cannot join in the reasons the order gave. 

He argued that whether the Monitor has sufficient access to the board was not at issue in the complaint, but rather whether the Monitor was justified in believing that issues raised at the LC are pertinent to the Monitor’s functioning. Christie also said state regulators often are reliant on the Monitor’s analysis and understanding of PJM’s markets and proposed changes.  

“The IMM is given very specific and vitally important duties, both in Order No. 719, which devotes an entire section to the importance of independent market monitoring in all RTOs, as well as, more specifically, in PJM’s specific [Open Access Transmission Tariff] Attachment M. If attending these meetings is ‘necessary or appropriate’ to the IMM doing its job, then the IMM should be allowed to make that decision,” Christie wrote. 

On the PSC West Virginia complaint, Christie said he believes the state commission failed to meet the burden of proof to file the complaint, but stated he believes there’s a larger issue of states not having adequate influence at RTOs when wholesale market or transmission changes can directly affect consumer rates. 

“There exists a much broader issue concerning RTO governance and decision-making that deserves attention, however, that unfortunately is not teed up in this proceeding, which I regard sadly as a missed opportunity … that broader issue is the very real and compelling need to redefine and elevate the roles and authorities of state regulators in all RTOs. State regulators regulate the retail rates paid by consumers, the rates that actually determine the monthly power bills that consumers must pay,” Christie wrote. 

He described the order’s consideration of whether the LC is a standing committee as “‘how many angels can dance on the head of a pin, legalistic hairsplitting,” but stated he does not believe granting state commissions access to the LC would have done much to advance their standing at RTOs even if the complaint had been granted. 

Posted on

FERC Approves $272K in ERO Standard Violation Penalties

In a March 1 ruling, FERC approved settlements between three utilities and their regional entities over violations of NERC’s reliability standards, bearing a total penalty for the companies of $272,000. 

NERC filed the settlements — between ITC and ReliabilityFirst, Evergy and the Midwest Reliability Organization, and the U.S. Army Corps of Engineers’ Mobile district (USACE-MOB) and SERC Reliability — in its monthly spreadsheet notice of penalty Jan. 31 (NP24-5). The ERO also filed a separate spreadsheet NOP that was nonpublic, in keeping with NERC and FERC’s policy regarding violations of the Critical Infrastructure Protection standards. FERC said in its March 1 filing that it would not further review the settlements, leaving the penalties intact. 

RF Knocks ITC for Rating Errors

ReliabilityFirst’s settlement involves a $150,000 penalty against ITC Michigan — composed of Michigan Electric Transmission (METC) and ITC Transmission — as well as ITC Midwest, which operates in Iowa, Minnesota, Wisconsin, Illinois and Missouri. Between them, the companies operate about 15,300 miles of transmission lines. 

RF alleged that the ITC companies infringed on FAC-009-1 (Establish and communicate facility ratings). The standard applies to both transmission owners and generator owners; the relevant section, Requirement R1, requires applicable entities to “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associate facility ratings methodology [FRM].” 

According to the settlement, METC notified RF in June 2020 that it and the other companies named in the complaint were in violation of FAC-008-1; RF decided “upon further analysis” to classify it under FAC-009-1 instead. The RE grouped a separate self-report submitted by ITC Transmission two years later in with this violation because it demonstrated “factual similarity and overlapping issues.” 

The entities identified 15 circuits in which the facility rating was inconsistent with the FRM, around 1.8% of their more than 800 applicable facilities. Of the affected facilities, three affected ITC Midwest and ITC Michigan, and nine affected ITC Transmission. All 15 needed to have their ratings adjusted downward, and three circuits exceeded their correct ratings at some point during the 12 years of the violation. 

RF determined the violation posed a moderate risk to the reliability of the grid, noting that accurate facility ratings are needed to ensure equipment is not operated in an unsafe manner. The RE observed that the duration of the violation “is extensive, dating back over a decade, and covering a period where NERC … put the entities on notice to potential issues and the associated risk in this area.” 

In mitigation, the ITC companies reviewed sag limit data for all circuits at each company and updated their facility ratings and associated documentation. They also implemented a geographic information system to provide better real-time data on their facilities. 

RF added that because the violation extended into MRO’s territory, the REs will split the penalty based on net energy load, with MRO receiving $51,000. 

MRO’s settlement with Evergy, which carries a $122,000 penalty, also concerns facility ratings. In this case, MRO alleged the utility violated FAC-008-3 (Facility ratings), the successor to FAC-009-1 that took effect in 2013; specifically, requirement R6, which is nearly identical to R1 of the earlier standard. FAC-008-3 since has been replaced by FAC-008-5. 

Evergy’s violation occurred in both its role as a generator owner and a transmission owner. According to MRO, Westar and Kansas City Power and Light (KCPL) — Evergy’s predecessors that merged in 2018 — submitted separate self-reports of similar issues prior to the merger. The RE later combined the reports as a single self-report under the Evergy name.  

Westar’s initial self-report identified ratings discrepancies at three generating facilities, while KCPL found discrepancies at three transmission lines and three generating facilities. MRO said “the entity” — whether it meant the post-merger Evergy or the two predecessors was unclear — “performed an extensive review of its facilities and identified two scope expansion issues” in the Westar transmission system. Evergy later performed field walkdowns on all 363 in-scope facilities as part of a mitigation plan that started in 2019. 

According to MRO, Evergy found facility ratings at 133 of its in-scope facilities, including 89 transmission lines, six generators, 28 reactive devices and 10 transformers. The RE identified the cause of the noncompliance as deficiencies in Evergy’s facility rating verification process. 

As with RF and ITC’s settlement, MRO classified the violation as a moderate risk. Although it was considered unlikely the violation would affect grid reliability, the RE noted the length of the violation — occurring over about six years from the time the misratings first were recorded in 2015 until Evergy completed its mitigation plan in 2021 — meant the risk could not be rated as minimal. 

On the other hand, MRO also acknowledged the completion of all mitigation activity, including validating all relevant equipment ratings and making physical modifications where needed to address ratings issues, and provided credit for cooperation, self-reporting and Evergy’s internal compliance program.  

Corps of Engineers Violation Spans 16 Years

SERC’s settlement with USACE-MOB, which carries no monetary penalty, arose from violations of PRC-005-1 (Transmission and generation protection system maintenance and testing) that began when the standard became enforceable in 2007 and were not addressed until 2023, when the successor standard PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) was in force. 

The RE determined via a compliance audit in April 2021 that as a generator operator, the Corps had “failed to maintain its components that are included within the time-based maintenance program” as required in PRC-005-6 (later determined to have begun under the earlier standard). SERC said it could not find any evidence that all of the required maintenance activities had been completed. It also found the Corps had not performed some of the obligatory maintenance activities within the past 18 months as the standard required. 

According to the NOP, SERC determined the cause of the issue was a “lack of internal controls” that could monitor and track compliance with the standard. The RE said the noncompliance posed a minimal risk to grid reliability, observing that none of the affected generators were part of a frequency response program or a black start or system restoration plan. In addition, SERC said there “is no common mode failure” for the affected systems and therefore “the likelihood that multiple generators would trip at the same time … is low.”  

Posted on

Crude Oil, Natural Gas Emissions Regs to be Published

New standards intended to reduce air emissions from the crude oil and natural gas industries are scheduled to be published this week. 

The EPA released the proposed rule in November 2021, supplemented it in December 2022 and announced the final rule in December 2023.  

The prepared text was posted Feb. 23. It will become effective 60 days after publication in the Federal Register, which is scheduled March 8. 

The standards cover new and existing facilities for production, processing, transport and storage of natural gas and crude petroleum. The sector is the largest U.S. industrial emitter of methane, a highly potent greenhouse gas blamed for one-third of the global warming resulting from human activity. 

EPA in December framed the new standards as a sweeping series of changes that would apply to hundreds of thousands of sources nationwide and prevent 58 million tons of methane emissions from 2024 to 2038, delivering health and economic benefits worth billions of dollars in the process. 

In the same time frame, EPA estimates reductions of 16 million tons of volatile organic compounds and 590,000 tons of various other toxic air pollutants that affect human health. It anticipates the prevention of the release of 400 billion cubic feet of fuel per year. 

“Standards of Performance for New, Reconstructed and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review” (Document No. 2024-00366) takes several approaches to meeting these goals: It encourages use of advanced technology for detecting methane, encourages continued innovation, sets up a program to identify the “super emitters” blamed for about half of the methane emissions from the oil and gas sector, bars flaring at new oil wells, sets zero-emissions standards for process controllers and pumps outside Alaska, and gives existing emitters three years to submit compliance plans. 

The 1,356-page unpublished version of the final rule lists four main components in its summary: 

    • finalizing revisions to the new source performance standards regulating greenhouse gases and volatile organic compounds emissions for the crude oil and natural gas source category pursuant to the Clean Air Act. 
    • finalizing emission guidelines for states to follow in developing, submitting and implementing state plans to establish performance standards to limit GHG emissions from existing sources in crude oil and natural gas sectors. 
    • finalizing several related actions stemming from the joint resolution of Congress on June 30, 2021, that disapproved EPA’s final 2020 rule for these emissions standards. 
    • finalizing a protocol under the general provisions for optical gas imaging. 

EPA said it received nearly a million comments on the November 2021 proposal and December 2022 supplement, ranging from support for the measures to a desire that they be further strengthened, to practical and cost concerns, to technical suggestions. 

After the rule was finalized in December 2023, it was hailed by groups such as the Environmental Defense Fund (“a major step forward in the fight against climate change”) and Clean Air Task Force (“worth the wait … worthy of celebration”). 

Others were not so happy. 

“The Biden administration has piled on another massive regulatory burden designed to encumber and even shut down American energy production,” said Sen. Kevin Cramer (R-N.D.), the nation’s No. 3 oil-producing state. 

The American Exploration & Production Council said: “While we appreciate EPA’s commitment to bringing all stakeholders to the table and see some improvement within the rule, other provisions remain flawed and risk undercutting U.S. production in the near and long-term.” 

Posted on

MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV

MISO on March 4 suggested an approximately $20 billion portfolio for its second long-range transmission planning (LRTP) effort, calling for several 765-kV line segments.  

The grid operator said its second LRTP draft portfolio for MISO Midwest “focuses on creating a 765-kV transmission ‘highway’ within the MISO region to maximize value based on land use, line distances, transfer levels and costs.” Together, MISO said the anticipated additions could range in cost from $17 billion to $23 billion.   

Several of the suggested 765-kV lines are located near 345-kV line routes approved as part of MISO’s first, $10 billion LRTP portfolio, including routes through Iowa that have been cast into uncertainty by a recent court ruling finding the state’s right of first refusal law unconstitutional. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.) 

The proposed 765-kV network snakes through Missouri, Iowa, Illinois, Wisconsin and Minnesota. Another suggested 765-kV segment cuts through Southern Michigan into Indiana. The second LRTP draft proposal also calls for several substations and more 345-kV lines in Minnesota, Wisconsin, Michigan, Iowa and Illinois.  

As with its first LRTP portfolio, MISO said it sought to minimize new rights-of-way permitting with state regulators to help head off environmental concerns. 

At the Gulf Coast Power Association’s MISO-SPP conference March 4, MISO CEO John Bear said the RTO hopes to finalize the second LRTP portfolio for approval by its board of directors at the end of the year.  

MISO planners have long said “significant” overloads and congestion eventually will threaten the system if the RTO doesn’t recommend a second set of Midwestern transmission solutions. (See MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio.) 

MISO’s new line suggestions are premised on the RTO’s estimate that it will need 369 GW of new, mostly renewable resources by 2042 based on its members’ plans. MISO said the second LRTP portfolio is the next step to “developing a system needed to reliably and efficiently meet the load growth and resource evolution described in MISO’s members’ plans.” 

“This portfolio focuses on creating a regional backbone to meet the long-term needs of our region,” MISO Vice President of System Planning Aubrey Johnson said in a press release. “Our transmission solutions — creating a sort of interstate highway system for electricity — enable the future resource plans of our states, utilities and members by addressing regional needs, while recognizing that local issues will continue to be addressed through our MTEP and generator interconnection queue processes.” 

“The future grid must be able to integrate new load growth and respond to extreme weather, and a robust transmission system is required to ensure this occurs reliably and efficiently,” said Laura Rauch, executive director of transmission planning at MISO. “We know further transmission development can provide value and we will continue working with our stakeholders to refine this portfolio and ensure it is sufficiently robust.” 

MISO said it will continue analyzing the benefits of anticipated portfolio over the coming months and take stakeholders’ suggestions for project alternatives through April 5.  

MISO will hold its next LRTP workshop with stakeholders on March 15.