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December 27, 2024

FERC Accepts NERC’s New Cybersecurity Standard

FERC on May 23 approved NERC’s proposed reliability standard for protecting electronic communication between control centers, along with the ERO’s plan for collecting data on winterization of generating units. 

NERC began development on CIP-012-2 (Cybersecurity — communications between control centers) in 2020, following a directive from the commission upon the approval of its predecessor CIP-012-1 (RD24-3). At the time, FERC said the standard needed further changes to protect the availability of communications links and data as required by Order 822, the impetus for the original standard. (See NERC Reliability Standards Get FERC Approval.) 

The ERO submitted the new standard in January, promising that it “expands the protections required by … CIP-012-1 by requiring responsible entities to mitigate the risk” of lost communications between control centers, along with the loss of real-time intra-control center assessment and monitoring data. 

NERC said the applicability and scope of CIP-012-2 are unchanged from the current standard; all responsible entities that own or operate control centers will be required to comply, except for facilities that “only communicate real-time data with other control centers regarding a co-located field asset [such as] a transmission station or generation facility.”  

The only change from CIP-012-1 is the addition of two new parts to requirement R1. Part 1.2 requires entities to implement protections for the availability of data in transit between control centers, while part 1.3 mandates that entities have methods for recovering lost communication links.  

In a filing, FERC said the proposed standard was “just, reasonable [and] not unduly discriminatory or preferential,” and addressed the directives in its order. The commission approved NERC’s request for the standard to take effect on the first day of the first quarter that comes 24 calendar months after the effective date of the order; as a result, the standard will become enforceable on July 1, 2026. 

ERO Outlines Data Collection Proposal

NERC’s cold weather data collection plan arose from FERC’s order last year approving EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations). (See FERC Orders New Reliability Standards in Response to Uri.)  

The commission directed NERC to submit within 12 months a plan for gathering data on generating unit winterization; for performing an analysis of the risk posed by proposed technical, commercial or operational constraints in EOP-012-1; and for analyzing the “actual performance of freeze protection measures during future extreme cold weather events.”  

NERC provided its plan to the commission in a compliance filing in February, explaining that it intends to submit an annual informational filing to FERC covering the required information; the first such filing will be made Oct. 1, 2025. Data for this first filing will be collected through a Section 1600 data request. This will be done for the second filing in 2026, possibly accompanied by additional data requests under NERC’s Compliance Monitoring and Enforcement Program. 

Information to be required from data requests to generator owners includes: 

    • identity and location of generating units; 
    • identity and megawatts of generation of units for which owners have declared constraints under EOP-012, along with the constraint declaration type and rationale; 
    • megawatts of generation within the owner’s fleet that are currently capable of operating at the unit’s extreme cold weather temperature;  
    • projected megawatts for which the generator owners and operators expect to implement and complete corrective action plans each year; 
    • the number of generator cold weather reliability events experienced in the previous winter; and 
    • megawatts of generating units that might be susceptible to the causes of the previous winter’s cold weather events. 

In its filing this week, FERC noted that no interventions or protests were filed by the March 12 due date. The commission concluded that the proposal meets its directives, and approved NERC’s data collection plan. 

FERC Forecasts High Temperatures, Flat Prices for Summer

This summer should bring high temperatures and electricity demand, but flat prices as cheaper fuel offsets higher load, according to FERC’s Summer Energy Market and Electric Reliability Assessment, released May 23. 

The National Oceanic and Atmospheric Administration forecasts a 60 to 70% likelihood of above-normal temperatures in June, July and August across the country compared with the 30-year average. 

High temperatures that are widespread can intensify stressed conditions on the electric grid by creating high electricity demand across a wide geographic area and reducing the availability of imported electricity from neighboring systems because they are also experiencing high demand,” the report said. 

Following last summer’s “El Niño” weather pattern, the National Weather Service says there is a 69% chance that a La Niña could emerge this summer. For the U.S., a La Niña means more storms in the center of the country and less precipitation in the South; it can also lead to more Atlantic hurricanes. 

NOAA released its hurricane forecast May 23 as well; it predicts an 85% chance of an above-normal season, with 17 to 25 named storms, eight to 13 forecast to become hurricanes, and four to seven of those to be major hurricanes. Forecasters have a 70% confidence in the ranges. 

Despite expectations for a hot summer, electricity prices are forecast to be flat or slightly lower than in 2023. The one exception is the Northeast, where regional natural gas prices could mean higher power prices than last year. 

FERC is forecasting average ISO-NE prices to be almost $10/MWh higher than last year, while those in CAISO are expected to fall by $23 to $34/MWh. 

U.S. installed generation capacity is expected to hit 1,207 GW, up 40 GW from 2023 because of additions of wind and solar, while retirements were dominated by coal capacity, with 3.3 GW retiring through September.  

ERCOT leads with 20.1 GW of capacity additions, including 12 GW of solar and 4.5 GW of batteries. CAISO is expected to add 8.9 GW overall, but it beats ERCOT, with 5.1 GW of battery capacity additions. 

Summer is the season with the highest use of natural gas for the sector, with power burn expected to peak in July and August at 47 Bcfd this year. 

“Natural gas used to generate electricity — or power burn — is expected to average 43.5 Bcfd in summer 2024, equal to power burn in summer 2023 but up 9.5% compared to the five-year average,” the report said. 

Coal stockpiles at power plants are higher this year, and coal delivery over the rail network does not face the same issues as the pandemic years from 2020 to 2022, but the Francis Scott Key Bridge collapse in Baltimore has impacted some local coal plants. 

“Coal power plants nearby may experience delays or disruptions to resupply coal stocks via water (barges) if there is protracted disruption to shipping in nearby waterways to clean up the bridge collapse,” the report said. “The bridge collapse temporarily halted coal deliveries by barge to the Brandon Shores and Wagner coal plants, totaling 1,865 MW, which are located directly adjacent to the bridge.” 

Baltimore is the second-largest port for coal exports, shipping the commodity from Appalachia to global markets and representing 28% of exports. That traffic was temporarily delayed because of the bridge collapse. 

The Energy Information Administration is expecting demand to be 2.7% higher this summer than last year and 4.4% over the average of the past five summers. 

“The expected larger electricity consumption this summer results from forecasted warm weather and strong economic growth,” the report said. “Another significant source of electricity consumption growth is the construction of new data centers in many regions of the country.” 

Is NV Energy Leaning to CAISO’s EDAM?

An NV Energy executive has provided the strongest public indication yet that the Nevada utility is poised to choose CAISO’s Extended Day-Ahead Market (EDAM) over SPP’s Markets+. 

Dave Rubin, federal energy policy director at NV Energy, offered the insight May 22 at a joint session of the CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body.  

A member of the West-Wide Governance Pathways Initiative’s Launch Committee, Rubin spoke during the committee’s presentation on the initiative’s proposal to alter the governance structure of CAISO’s WEIM and — by extension — the EDAM, which will extend the capabilities of the real-time WEIM.  

Step 1 of the Pathways proposal calls for the WEIM’s Governing Body to assume “primary” authority over WEIM/EDAM matters, elevating its power from the “joint” authority it currently shares with the CAISO board over such matters. The move represents the limit of ISO governance changes that can be made under current California law, according to legal analysis performed for the Pathways Initiative. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.)   

Step 2 of the plan seeks to create “a durable governance structure with a fully independent board that has sole authority to determine the market rules for EDAM and WEIM,” which will require changes to California law, something Pathways Initiative backers are pursuing through engagement with the legislature. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)     

In speaking at the May 22 meeting, Rubin said Step 1 “inspires confidence, not only for moving to a form of solid independent authority at some point over the EDAM and EIM in Step 2, but also for the continued engagement of the [Pathways] parties as we expand market services for the benefit of our customers.” 

Rubin said NV Energy has been impressed by the “engagement and encouragement” around Step 1 and the Pathways Initiative by CAISO’s staff and board and the WEIM’s Governing Body that “we believe demonstrate a common understanding of the importance of independent market governance.” 

“It’s certainly one thing to discuss that as a goal, but it’s far more meaningful to take concrete actions to further that objective. And accordingly, for NV Energy, we’ve strongly supported the work of the Launch Committee, and it clearly helps inform our market evaluation,” he said. 

While Rubin’s comments fell well short of an announcement in favor of EDAM, they came during a week when multiple electricity industry sources in the West told RTO Insider that NV Energy officials have been circulating the idea that the utility plans to join the CAISO day-ahead market but probably won’t make an announcement before filing with Nevada regulators. 

The utility did not respond to a request for comment. 

NV Energy in Key Position

An NV Energy decision in favor of EDAM would be pivotal for CAISO and the Pathways Initiative for at least two reasons. 

First, because of its central location in the West, NV Energy’s transmission network has been a key transit point for energy transfers — or wheel-throughs — among balancing authority areas of WEIM participants since it joined the market in 2015. It likely would continue to fulfill that vital function for the EDAM, while also hindering the ability of potential Markets+ participants in the Northwest and Desert Southwest from transacting freely with each other. 

Second, the Pathways proposal stipulates that CAISO’s filing of WEIM primary authority tariff changes with FERC wouldn’t be triggered until EDAM obtains implementation agreements from a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of the CAISO BAA annual load in 2022.  

The EDAM last month secured a full commitment from PacifiCorp and has received tentative — but solid — commitments from Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric. Given that, a utility of NV Energy’s size and location would provide the trigger for CAISO to file the Step 1 change once it emerges from the ISO’s stakeholder process. 

A study published this year by The Brattle Group showed NV Energy could earn as much as $149 million in annual benefits as a member of EDAM versus a top-end benefit of $16 million in Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

Glick, Christie Clash over States’ Role in FERC Order 1920

VAIL, Colo. — Former FERC Chair Richard Glick faced off against his old colleague, Commissioner Mark Christie, over FERC Order 1920 in the general session of the Western Conference of Public Service Commissioners’ annual summit May 21. 

The order, which directs regional transmission planners to alter their processes to be more forward-looking and proactive, stemmed from a Notice of Proposed Rulemaking issued in 2022 under Glick’s leadership and with Christie’s enthusiastic support because of its consideration of state input. But Christie dissented from the order, which didn’t contain the provisions that had led to him voting for the NOPR. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

“The NOPR gave states a very significant role, particularly in the key functions of the selection criteria for determining what projects go into the regional plan,” Christie said. It also gave states the ability to choose benefits, of which the rule outlines seven, that are key in determining who pays for transmission.  

“The rule actually mandates benefits, which NARUC [the National Association of Regulatory Utility Commissioners], specifically in their comments, said, ‘Don’t mandate benefits; let each region decide what works for them.’ The rule went in the opposite direction,” Christie said. “And of course, the most important issue of all is cost allocation. The NOPR promised that states would consent. … That was critically important to NARUC; it was critically important to every state organization; and it was critically important to me.” 

Order 1920 gives states six months to agree on a cost allocation mechanism with regional transmission planners, who must come up with a default ex ante method. Departing from the NOPR, regional planners are not required to file any agreement with the states or even any state proposals as alternatives.  

“What this rule does is leave states in the position of just being a stakeholder,” Christie said. 

But Glick defended the order and expressed uncertainty about the role of the six-month timeline, which, according to Christie, would be “extraordinarily difficult” for states to reach an agreement in. 

“Heck, I don’t know if six months is too long or too short, but at least there’s an opportunity to get together,” Glick said. “The states have an opportunity in this engagement process to come up with a state agreement cost allocation approach and process.” 

Christie also took issue with elimination of the FERC Order 1000 cost allocation principle 6, which held that transmission providers could have a different allocation process for public policy projects. In Order 1920, all projects are in the same bucket, “which is going to make it extremely difficult in the real-world practical application determining how much of a cost in one of these long-term projects is actually public policy,” Christie said. 

Glick emphasized that the benefits are for the purpose of project selection, not for the purpose of allocating transmission costs. 

‘Massive Wealth Transfer’

Mandating benefits and minimizing state consent over cost allocation will be problematic for the consumers who will bear the burden of transmission costs, argued Vincent Duane, principal at Copper Monarch and former general counsel for PJM. He joined Glick and Christie on the panel. 

“The way this rule is drawing a lot of criticism, and in my opinion rightly so, is that it does potentially represent a massive wealth transfer away from generation developers … and picked up by customers,” Duane said. 

Christie agreed. “This rule is absolutely about a massive transfer of wealth from consumers to developers, no question about it,” he said.  

Glick again pushed back, saying the rule will ensure that costs can only be allocated to customers to the extent they benefit.

“It’s not a wealth transfer,” he said. “The customers are only going to have to pay where they benefit.” 

To ensure protection of consumers, Christie said state regulators should have a more robust role than the order gives them. 

Duane boiled the conversation down to weighing the inevitable compromises that will be made as Western electricity markets expand and utilities and power providers decide which day-ahead market to join.  

“There’s going to be some degree of surrendering of state sovereignty as a result of regionalizing. … There’s going to be some potential that you’re going to be told you’re a beneficiary when you may not feel you’re a beneficiary,” Duane said. “As state policymakers, the question you’re facing is, do the benefits of being a part of a regional organization that plans regionally across multiple jurisdictions — that requires some give and take, and some rough and tumble, and some unscientific, at the end of the day, benefits and costs — is it worth it?” 

FERC OKs Allete Securities Sale Prior to Acquisition

FERC has granted Allete permission to sell several hundred million dollars in securities to raise funds for its clean energy transition.  

In a May 23 order, FERC said Allete is clear to issue stock and up to $977 million in short-term debt, up to $275 million in long-term debt and a maximum of $516 million in the sale of tax credits and tax equity financing (ES23-71). The commission’s authorizations are good for two years.  

Allete’s ask to FERC predated its acquisition announcement this month. The company said it needs money for continued investments in renewable energy, “environmental technology” for its generating units, transmission investments and distribution grid modernization, and other business expenses.   

FERC said Allete’s request to raise money appeared consistent with the public interest and “reasonably” necessary for Allete’s utility services.  

Allete said it filed for FERC permission out of an “abundance of caution” because its utility, Minnesota Power, owns and operates wind generation in North Dakota. Last year, the Minnesota Public Utilities Commission authorized the company to issue long- and short-term debt.  

At the time of filing, Allete said it expects its affiliates’ capital expenses to overtake its internal cash flow from January 2023 through June 2024.  

Allete said with “internally generated cash insufficient to fund the planned capital outlays,” it will need to turn to issuances of long- and short-term debt and common stock alongside tax equity financing. Allete also noted in the filing it had been exploring acquisition “and other investment opportunities to diversify [its] revenue base in order to reduce its dependence on revenues from a concentrated industrial base of taconite and paper customers in northeastern Minnesota.”  

Allete’s hunt for a buyer proved successful. Weeks ago, it announced an agreement to be acquired by Canada’s pension investment board and private equity firm Global Infrastructure Partners for more than $6 billion. The acquisition and ensuing transition to a private company would help it access even more capital to navigate fleet transition, the company said. (See Canada Pension Board, Global Infrastructure Partners to Buy Allete.)  

Allete said it hopes to finalize the deal in 2025. The sale requires approvals from FERC, Minnesota and Wisconsin regulators, the Federal Trade Commission and company shareholders. 

MISO: Worsening Uninstructed Deviation Needs Attention

Five years after it introduced rules to curb generators’ uninstructed deviations from dispatch instructions, MISO said such departures are worse than ever and it likely needs to strengthen rules and software. 

“Despite an initial increase in dispatch-following performance since the 2019 uninstructed deviation changes, the fleet is now performing below” pre-rule levels, MISO Market Settlements Adviser Mollie Dawson said at a May 23 Market Subcommittee meeting. She said the high number of departures from dispatch instructions remains attributable to renewable energy sources.  

MISO said it will mount a “multifaceted approach” that may include new market rules and operational tools. The RTO said it will draft the changes in collaboration with its Independent Market Monitor and stakeholders.  

“Our current rules are not meeting the challenge of the impact,” Dawson said.  

Dawson said new potential fixes might include MISO introducing settlement penalties, stepped-up requirements to follow MISO-generated setpoints, capping use of manual dispatch and improving its forecast output of intermittent resources.  

Dawson said MISO will consult with its Independent Market Monitor in July and bring a slate of potential solutions to stakeholders for evaluation in August.  

MISO four years ago placed harsher tolerance limits on generation operators’ deviations from its dispatch orders. The rules determine a generator’s deviations by comparing the time-weighted average of a real-time ramp rate with a day-ahead offered ramp rate, while allowing for 12% tolerance from setpoint instructions. The rules at the time eliminated the RTO’s “all-or-nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds earn make-whole payments in proportion to performance.  

Before then, generators in MISO were flagged when they deviated by more than 8% from dispatch signals over four consecutive intervals. (See MISO Plans for New Uninstructed Deviation Rules.) 

MISO IMM David Patton last year recommended MISO improve its near-term wind forecasting to better reflect the characteristics of wind generation output. He said MISO currently uses a “persistence” forecast that assumes wind resources will produce the same amount of output as it most recently observed. MISO stakeholders have said that forecasting style is problematic when wind dies down suddenly. (See MISO Shelves IMM’s Transmission Planning Recommendation in State of the Market Report.)  

After MISO implemented its uninstructed rules in mid-2019, Patton said more wind operators migrated to using MISO’s wind forecasts instead of their own, less accurate forecasts.  

National Grid Plans $35B Investment in NY, Mass.

National Grid plans to invest $75 billion in its infrastructure over the next five years, nearly half of it in New York and Massachusetts. 

The UK energy company announced the plan May 23 with its year-end financial results and said the $35 billion investment in the two states would be over 60% higher than in the past five years. 

National Grid also announced it would sell National Grid Renewables, its U.S. onshore renewables business, and Grain LNG, its UK LNG asset, as it focuses more closely on its energy networks. 

In a news release, National Grid said the New York and Massachusetts projects would harden the electric grid, reduce emissions and provide benefits to both customers and local economies. 

The company noted the Department of Energy in its 2023 National Transmission Needs Study forecast a need for a 255% increase in transmission development to support the two states’ anticipated clean energy growth. 

The news release emphasized the investments in electric networks and the resulting benefits for states’ decarbonization goals. But the financial report indicates a little more than 40% of the $35 billion would be spent on natural gas infrastructure, including a proposed three-year, $5 billion modernization of National Grid’s downstate New York gas businesses. 

Continued investment in gas infrastructure has been a friction point between utilities and decarbonization advocates. National Grid notes that the work planned would be for safety and reliability purposes and would provide environmental benefits by reducing leaks. 

In total, National Grid said it plans to invest about $21 billion in New York through March 2029. More than $4 billion of this would go to the Upstate Upgrade, a portfolio of more than 70 transmission enhancements designed to increase reliability, resilience and capacity.  

As it announced the upgrade in March 2024, the company called it the largest investment in the grid in its century-plus existence — building, rebuilding or modernizing more than 1,000 miles of transmission line. As a result, 45 substations would be built, rebuilt or modernized. 

The New England investment would total about $14 billion and include smart meters, modernized infrastructure, hardening against extreme weather and quality upgrades to electric and gas assets. Part of this would be National Grid’s Electric Sector Modernization Plan, a $2 billion proposal submitted to Massachusetts regulators as part of the state’s drive to upgrade the grid and accelerate connection of renewables. 

The dollar figures are approximate and are based on present UK-U.S. currency exchange rates. 

The plan involves an equity raise of 7 billion British pounds, or nearly $9 billion. 

The company’s share price, which recently traded near 52-week highs, took a dive after the plan was announced, closing 10.9% lower May 23 on the London Stock Exchange and 14.3% lower on the New York Stock Exchange. 

For the fiscal year ended March 31, National Grid’s operating profit was down 8% from the previous fiscal year, its pre-tax profit was down 15% and its earnings per share were down 19%. 

NJ Wrestles with Clean Energy Priorities

A New Jersey campaign to solicit public opinion on a new Energy Master Plan has sparked intense and diverging opinions, with state officials claiming achievements triggered by the previous plan and environmentalists charging the next plan should be tougher, bolder and more aggressive.

Speakers at the first of four public hearings organized by the New Jersey Board of Public Utilities urged the agency to emphasize cutting emissions from heavy- and medium-duty trucks and aggressively tackle methane emissions. Several speakers at the May 20 hearing asked the BPU to do more to reduce vehicle miles traveled in the state and push public transit, while business groups demanded closer attention to the cost of the plan.

The discussions follow the 2019 Energy Master Plan, which environmentalists depicted in the hearings as too timid and ineffective.

“The 2019 plan wasn’t strong enough, wasn’t really implemented,” said David Pringle of Empower NJ, a climate coalition. And he expressed concern that the next version would have the same impact because it won’t be completed until the final months of Gov. Phil Murphy’s tenure, which ends in January 2026.

BPU officials said they expect to complete a draft of the new plan by the third quarter, and the final report by the end of the year. That will form the cornerstone of the state’s “comprehensive climate action plan,” with a release target date of the third quarter of 2025, said Eric Miller, executive director of Murphy’s Office of Climate Action in the Green Economy.

Miller said the goal of the master plan initiative is to “identify the best pathways for New Jersey to achieve its ambitious climate targets.” It will build upon the 2019 plan and adapt to the changes that have taken place since, such as new clean energy goals and money available through the federal Inflation Reduction Act, he said.

“We’ll be conducting a deeper and more robust study of the cost of climate mitigation for our residents,” Miller said. That will include “detailed gas and electric rate modeling, in addition to the upfront capital costs associated with decarbonization” and will enable the state to “more deeply explore how a diverse range of demand reduction strategies may help alleviate peak electric load.”

Clean Energy Advances

Whatever its impact, the 2019 New Jersey plan came as the state embarked on a series of clean energy initiatives considered among the more aggressive in the nation.

The state, which already had a strong portfolio of solar projects when the previous master plan was created, has continued to add solar capacity, launching a highly popular — and oversubscribed — community solar program.

State incentive programs had by the end of 2023 helped put 154,153 electric vehicles on the road, about halfway to the goal of 330,000 by 2025. The state also has heavily backed offshore wind energy, approving five projects and building a $600 million wind port. The state suffered a setback in October when developer Ørsted abandoned two projects, but three OSW projects with a capacity of 5.25 GW are ongoing, and the state launched a fourth solicitation on April 30. (See New Jersey Opens 4th Offshore Wind Solicitation.)

In September 2021, Murphy increased the state’s OSW capacity target from 7.5 GW to 11 GW by 2040. That followed the governor’s moving forward the goal of reaching 100% clean energy electricity generation from 2050 to 2035.

In advance of the public hearings, the BPU issued a request for information seeking stakeholder input at the first meeting on a range of topics, among them how to shape the state’s EV incentives as uptake progresses, and how to support and accelerate the development of the OSW and solar projects without placing too much burden on ratepayers.

Cost is Key

The cost of implementing the final plan emerged as a consistent theme at the more than three-hour meeting, at which about 50 people spoke.

The New Jersey Chamber of Commerce said it supports the state’s OSW initiatives and the goals of the Energy Master Plan but urged the BPU to hire an “independent, outside organization” to study the costs and ratepayer impact.

“Transparency in costs is essential to ensuring the success of the implementation,” said Laura Gunn, a lobbyist for the chamber.

Doug O’Malley, state director of Environment NJ, said the state needs to be ready to provide financial support for whatever proposals end up in the plan.

“We can solve our climate crisis by investing in clean energy, including energy storage,” he said. “The missing ingredient of past Energy Master Plans and the future ones is that it needs funding, and it needs funding from the Murphy administration that will meet the moment and meet the challenge, to ensure that we’re not underfunding the solutions.”

Any assessment of the cost of the plan should take into account the cost of “inactivity,” the expenses arising from the extreme impacts of climate change if the state does not combat climate change, he said.

Peggy Middaugh, of Unitarian Universalist FaithAction NJ, also said the BPU should go beyond calculating the costs of implementing initiatives to include the broader costs that would result if the state failed to cut emissions, such as health costs, property damage from wildfires and flooding, and “the reduction in value of real estate in flood-prone areas.”

Reducing Miles Traveled

Middaugh added that cutting emissions from transportation should be a key element of the master plan, including efforts to reduce emissions by using EVs or bolstering the state mass transit agency so more people will use it.

But the plan should go much further and seek to cut the distance that people travel to get to work, she said.

“In almost all New Jersey municipalities, a large majority of the residents leave town to go elsewhere to work while a large majority of the jobs in the municipality are filled by non-residents,” Middaugh said. “This requires a deep examination of development and our transportation infrastructure.”

Chris Sturm, policy director of land use for New Jersey Future, a nonprofit organization that promotes sustainable growth, said vehicle miles traveled statewide have increased annually for most of the past 50 years, and the organization has crafted a plan to reduce the number by 8.5% by 2050. Implementation would include measures such as investing in bike and pedestrian infrastructure and mass transit, and creating municipal developments that put homes closer to grocery stores, schools and bus stops.

John Reichman of Empower NJ said the most effective step toward reducing vehicle miles traveled would be to “stop expanding highways and instead invest that money in public transit” and pedestrian walkways. He urged the state to stop the expansion of the New Jersey Turnpike just outside New York City, which he said would cost $10.7 billion.

“Prioritizing expanding highways is a policy of the 1950s that totally ignores the climate crisis,” he said.

Speakers also offered diverging opinions as to what should be considered clean energy.

Gunn urged the BPU to take a broad view of acceptable energies, including natural gas, nuclear, renewable natural gas and hydrogen, and to “recognize the vital importance of the state’s gas distribution system going forward.”

“The more options our residents and businesses have as it relates to energy production in New Jersey, the more affordable it will be,” she said.

But environmental groups encouraged a much harder line, with some calling for a moratorium on the development of any fossil fuel generating plants and urging the BPU not to accept alternative fuels that are not 100% clean energy.

NERC Says IBR Work Proceeding as Planned

A year on from FERC’s approval of NERC’s work plan for registering inverter-based resources (IBRs) such as solar and wind facilities, representatives from the ERO and its regional entities say the task is on track to conclude on schedule. 

Speaking at a webinar hosted by the Texas Reliability Entity, Howard Gugel, NERC’s vice president of regulatory oversight, said the ERO is in the second phase of the road map it laid out in its work plan, which the commission accepted May 18, 2023. (See FERC Approves NERC’s IBR Work Plan.) 

The plan follows a framework FERC described in a November 2022 order directing NERC to register IBRs that are not currently required to register with it but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation. According to FERC’s order, the ERO must complete any necessary modifications to its registration processes by 12 months after the commission approves its work plan, identify owners and operators of relevant IBRs within 24 months of approval and register them no later than 36 months after approval. 

In a progress update, Gugel said NERC’s Board of Trustees approved the appropriate changes to its Rules of Procedure (ROP) at a special meeting in February and filed them with the commission the following month, requesting an expedited review period of 60 days (RD22-4). FERC accepted comments on the proposal from industry stakeholders through April 18. 

“They are in the process right now [of] reviewing those comments, and we are hoping that they will provide some more guidance — either accepting our registration criteria or proposing … some further modifications — sometime in the very near future,” Gugel said. 

The proposed ROP changes would create a new category for entities that own or operate IBRs that either have or contribute to an aggregate nameplate capacity of at least 20 MVA and are connected to a common point of connection with a voltage of at least 60 kV. 

Currently, the ERO is using data from the U.S. Energy Information Administration and other sources to identify those resources ahead of FERC’s expected approval of the ROP updates. It is also drafting a request for information to be sent to registered entities, starting with balancing authorities and transmission owners, as soon as FERC has given its assent. 

Gugel also updated attendees on the ERO’s IBR-related standard development projects, which are also the subject of a FERC order issued last October. The commission directed NERC to submit standards aimed at improving the reliability of IBRs in three tranches beginning in 2024. 

At the moment, Gugel said, NERC has prioritized the first set of standards, which concern performance requirements and post-event performance validation for registered IBRs. These standards must be sent to FERC for approval by Nov. 4. 

The next set of standards will address data sharing and model validation for IBRs, to be completed by November 2025. The final tranche to be finished by November 2026 will concern planning and operational studies. 

Massachusetts DPU Approves Everett LNG Contracts

The Massachusetts Department of Public Utilities has approved agreements between Constellation Energy and the state’s investor-owned gas utilities to keep the Everett LNG import facility operating through May 2030. 

The Everett Marine Terminal (EMT) is the only facility in the state that can import and directly inject LNG into the gas network, but it has faced an uncertain future, with Constellation’s cost-of-service agreement with ISO-NE expiring at the end of this month. Constellation owns both Everett and the Mystic Generating Station, Everett’s anchor customer, which is set to retire at the same time. 

Following extended negotiations with the state’s gas utilities dating back to 2021, National Grid, Eversource Energy and Unitil filed agreements with Constellation in February to help cover the facility’s fixed costs and provide the utilities the option to purchase LNG as needed. 

The utilities argued that the agreements were necessary for the reliability of the gas network, but they were met with pushback by environmental organizations and state agencies about the cost and climate implications of the agreements. The Conservation Law Foundation (CLF) opposed the agreements, while groups including Enbridge, Tennessee Gas Pipeline and Constellation supported the utilities’ filings. 

Neither the Massachusetts Attorney General’s Office nor the state Department of Energy Resources took an explicit stance on the contracts, but both called for additional transparency and reporting requirements. (See Mass. AGO, DOER Call for Climate Guardrails on Everett LNG Contracts.) 

In its ruling, the DPU found that “without the agreements, each company will not have sufficient natural gas supplies to reliably serve its customers in design-winter scenarios during the term of the agreements, which could jeopardize the health and safety of its customers during the cold winter months.” 

Responding to CLF’s argument that utilities did not adequately consider alternatives, the DPU ruled that “the alternatives to the agreements currently available to each company, including electrification, are insufficient to fully replace supplies from EMT or provide the reliability benefits that EMT offers.” 

The DPU also disagreed with CLF’s contention that the agreements are not compatible with the state’s climate laws. The department noted that Eversource’s and Unitil’s contracts are intended to replace existing gas supply contracts and are therefore in line with the precedent set by previous rulings. 

Meanwhile, National Grid indicated that its contract is needed in part to help meet increasing gas demand from oil-to-gas heating conversions. The department found that this justification is aligned with previous rulings “that the acquisition of incremental natural gas supply to serve new customers that convert from oil heating to natural gas heating is consistent with the” Global Warming Solutions Act. 

However, the DPU wrote that it may need to revisit this precedent following its December 2023 order (20-80-B) creating “a new regulatory framework” to discourage new investments in gas infrastructure. (See Massachusetts Moves to Limit New Gas Infrastructure.) The department also said it intends to consider whether equity and affordability impacts should be included in the evaluation of similar contracts going forward. 

Instead of changing the standard of review within the Everett proceedings, “the department finds it appropriate to engage in a more thoughtful, comprehensive process involving the participation of all interested stakeholders,” the DPU wrote. 

The department agreed to include annual transparency and reporting requirements around the cost and climate effects of the agreements, as well as on the utilities’ efforts to reduce their need for Everett. 

“We agree with the attorney general and DOER that open and transparent insight into the companies’ efforts to reduce or eliminate their reliance on EMT is critical to ensuring that the commonwealth remains on a path to achieve its decarbonization goals,” the DPU wrote. 

Throughout the process, climate and environmental advocates in the state have expressed concern that the contracts could function as a stop-gap measure to a more permanent pipeline capacity expansion into the Northeast. Enbridge has said it could complete a major capacity expansion of the Algonquin pipeline by the end of the decade. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Joe LaRusso, senior advocate at the Acadia Center, said the DPU’s approval of the contracts is “potentially in conflict with Order 20-80,” particularly if the contract timelines are intended to align with Enbridge’s pipeline expansion effort. 

He said the reporting requirements should give the DPU ample information on the utilities’ gas demand trajectories, with the “open question” being whether the DPU allows the companies to reduce their reliance on Everett by securing additional pipeline capacity. 

Meanwhile, Constellation applauded the DPU’s ruling, writing in a statement that the contracts will help “ensure adequate gas availability during extreme weather conditions as the region transitions to clean energy.”