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July 7, 2024

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President Biden’s LNG Pause Fuels Partisan Debate at House Hearing

Republicans teed off on President Biden’s pause on processing new applications for LNG exports at a congressional hearing Feb. 6. (See Report: Biden Admin to Evaluate LNG Terminals’ Impact on Climate.)

“In addition to undercutting our domestic energy industry, President Biden’s decision is a gift to Vladimir Putin,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy, Climate & Grid Security Subcommittee. “Global demand for natural gas is expected to increase 46% by 2050. And our European and Asian allies who want to do business with the United States will now look to Qatar, Russia and Iran to meet their growing energy needs.”

Duncan said committee leaders had invited a speaker from the Department of Energy, but nobody from the administration came. Undersecretary of Energy David Turk is scheduled to testify on the subject at a Senate Energy & Natural Resources Committee hearing Feb. 8.

The pause comes after the industry already has built enough capacity to export 14 billion cubic feet per day, with enough under construction to double that capacity, said Subcommittee Ranking Member Diana DeGette (D-Colo.). Additional projects with full approvals from FERC and DOE, but yet to start construction, would triple that capacity, DeGette said.

None of those facilities under development will be affected by the pause in reviews, she added. The last time the review process for new export facilities was updated was 2018, when export capacity was just one-third of today’s level.

“The fact that our nation’s production has ramped up so quickly must be considered, especially since the U.S. currently has enough approved capacity to fulfill the world’s energy needs in the short and medium terms,” DeGette said. “Continuously increasing LNG exports, without updating guidelines to account for new information, is a fundamentally unserious proposal.”

EQT calls itself the largest producer of natural gas in the country, with its drilling focused around the Marcellus and Utica shales in Pennsylvania, Ohio and West Virginia. EQT CEO Toby Rice blasted the decision to pause approvals for new export facilities.

“The Biden administration’s decision was pure politics,” Rice said. “The moratorium was made under the guise of updated research and a claim that we needed updated studies on the environmental and economic impact of U.S. LNG. But we all know what it really is, and that’s an election-year stall designed to garner votes.”

Europe has had to rely on importing LNG from the U.S. since its countries were cut off from Russia following its invasion of Ukraine, said Brigham McCown, senior fellow at the Hudson Institute. Last month, spot prices there averaged $9.56/MMBtu (million British thermal units), while Henry Hub gas was at just $2.26/MMBtu this week, McCown said.

“Europe should not be allowed to recede into the background,” McCown said. “Energy security highlights the need for a comprehensive approach and a stable policy environment coupled with innovation, technology and international cooperation. Our allies would like to be able to have energy security as well.”

Gillian Giannetti is a former high school teacher along the part of Louisiana’s coast called “cancer alley” because of the concentration of industrial facilities and their pollution’s impact on locals. Now senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, Giannetti said she’s witnessed the effects on her former students, who had high rates of asthma and other respiratory conditions.

The pause impacts only LNG facilities being built to serve countries that do not have a free-trade agreement with the U.S., she noted. DOE must find that a facility shipping gas to non-free trade countries is in the “public interest” to approve it, and so far, it has yet to deny an application for any facility, Giannetti said.

“Put simply, DOE’s tools for assessing whether future gas exports are consistent with the public interest are both obsolete and inapplicable,” she added. “First, DOE has never published guidelines for evaluating the public interest for LNG exports. Never.”

The closest it came was a 1984 effort that sought to come up with rules for LNG imports, which do not work well for licensing export facilities four decades later, Giannetti said. DOE did do some studies on the economic impact of LNG exports in 2018, but they need to be updated too, she added.

The Industrial Energy Consumers of America (IECA) was not invited to testify, but it released comments saying LNG exports affect domestic prices, especially when storage is low. That coincides with demand peaks, which the IECA claims contributed to $84 billion and $53 billion in higher natural gas and electricity prices in 2022 compared to a year earlier.

“Accelerating volumes of LNG exports do have increasing impacts to reliability and prices of natural gas and electricity that are accentuated when inventories are low and during peak winter and summer demand,” said IECA President Paul Cicio. “The relationship is fundamental to the law of supply and demand. Low inventories result in high prices and high inventories result in low prices.”

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New Jersey Senators Back Grid Connection Fee Revision

New Jersey’s Senate Environment and Energy Committee endorsed a sweeping revision of how clean energy connections to the grid are funded and advanced legislation that would give tax credits to help install electric vehicle charging stations and retrofit warehouses for rooftop solar projects. 

The five-member committee on Feb. 5 unanimously supported S209, which would make warehouse retrofit projects eligible for corporate business tax credits of the lesser of $250,000 or half the cost of the project for buildings of at least 100,000 square feet. The bill sets a cumulative total of $25 million awarded in credits under the bill. 

The panel voted 4-1 in favor of a second bill, S210, that would provide a tax credit of the lesser of half the cost or $1,000 to pay for an EV charger at a taxpayer’s business, trade or occupation, or at a location where it could be used by tenants or guests of a multifamily or mixed-use property. 

The bill also would offer a tax credit for the purchase of a commercial zero emission vehicle that would equal half the additional cost of buying a clean energy vehicle rather than one powered by fossil fuel. The bill would allow for a tax credit of up to $25,000 for a vehicle weighing less than 14,000 pounds, $50,000 for a vehicle weighing between 14,000 and 26,500 pounds, and $100,000 for a vehicle weighing more than 26,500 pounds. 

Preparing the Grid

Other bills met more resistance in the committee, which handles much of the state’s clean energy legislation. 

The Democrat-controlled committee voted 3-2 along party lines for a bill, S212, that would revise the regulations that set interconnection standards for Class 1 renewable energy sources, crafting them in line with standards written by the Interstate Renewable Energy Council (IREC). 

The changes would include the introduction of fixed, one-time “grid modernization fees” to be paid by the project owner to defray the cost of connecting to the grid, “including, but not limited to, costs related to administrative tasks, studies, infrastructure upgrades and grid upgrades carried out by the electric utility.” The fees would be based on the number of kilowatts of energy to be produced by the project, with a limit of $50 per kilowatt for projects less than or equal to 10 kilowatts. 

Connection costs not covered by the developer fees would be recovered by the utility from the ratepayers. 

Sen. Bob Smith (D), the committee chairman and a bill co-sponsor, said the legislation is aimed at strengthening the state’s ailing grid, which is considered inadequate to handle a surge of new clean energy projects. 

“We have a grid that is the equivalent of toothpicks and chewing gum,” Smith said, adding there are lengthy delays before a project can get connected, during which the project often “dies as a result.”  

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, said the urgency of the initiative can be seen in his agency’s estimate that on a clear day, solar projects provide 35% of the state’s load between 10 a.m. and 3 p.m. The state has reached an “inflection point,” and the improvements funded by the bill are essential, he said. 

“We’re almost in a crisis where the grid is shutting down to new solar,” he said. 

But Brian O. Lipman, director of the New Jersey Division of Rate Counsel, in a Feb. 1 letter to the committee, urged senators to hold the bill because it would create “avoidable and expensive electric system upgrades that will be foisted onto captive ratepayers.” 

Lipman said the current “beneficiary pays principle” means that developers and the utilities make “efficient siting decisions” because projects for which the connection costs are too high won’t go ahead. “The risk is better handled by the interconnection customer than captive end-use customers,” he said. 

Subsidizing Storage

Lipman also opposed S225, which would create an incentive program to support new energy storage systems. New Jersey, like other states, sees an extensive storage capacity as key to creating a renewable energy system that is reliable. But the state has little storage capacity. It failed to reach a legislative goal of installing 600 MW of storage by 2021 and now aims to install 2 GW of storage by 2030. (See New Jersey Offers Plan to Boost Lagging Storage Capacity.) 

S225, which the committee approved in a 3-2 vote, would require the New Jersey Board of Public Utilities (NJ BPU) to develop a pilot — and later permanent — program that would award up-front incentives paid in dollars per kilowatt-hour based on the installed capacity of the storage system. The incentive would cover up to 40% of the project cost. 

The program would pay a “performance incentive to compensate the owner of a customer-sited energy storage system or front-of-the-meter energy storage system” for the cost of providing “capacity, demand response, load shifting, generation shifting, locational value and voltage support,” according to the bill. It says the cost of the incentives would be “apportioned” to ratepayers. 

Lipman, in a Feb. 1 letter to the committee, expressed concern the bill would “impose significant costs on New Jersey’s electric ratepayers, while impairing the state’s ability to leverage other sources of funding for energy storage.” He estimated the incentives would cost the state’s societal benefits charge program $60 million. 

But Evan Vaughan, executive director of the Mid-Atlantic Renewable Energy Coalition, said he believed it would “help the market take off in the state.” 

“We have numerous front-of-the-meter storage companies in our membership that are eager to develop projects in New Jersey,” he said. “But they need this legislation in order to make those projects pencil.” 

Discussion Dispute

Two bills discussed by the committee in order to solicit input, but not voted on, drew vigorous opposition from the business community, while drawing support from environmental groups. 

SCR11 would amend the state constitution to prohibit the construction or reconstruction of any new power station that would burn coal, natural gas, oil or petroleum. If approved by the legislature, the proposed prohibition would need voter support in a ballot initiative to be enacted. 

Smith, the bill sponsor, said about 35% of the state’s electricity is generated by nuclear plants and 7% comes from solar projects. The remaining 55% comes from carbon-emitting plants, mostly natural gas. 

Michael Egenton, executive vice president at the New Jersey Chamber of Commerce, said changing the constitution over the issue is excessive, and added that prohibiting the plants would stifle the state’s ability to grow and keep businesses. 

“We have to make sure that we have reliable, affordable, sustainable energy — and I’m talking about energy all across the board,” he said. 

Tina Weishaus, co-chair of the DivestNJ Coalition, and a member of Empower New Jersey, which opposes fossil fuel projects, said that given the health damage to nearby communities, operating such plants is “morally wrong.” 

“We cannot live in a world that continues to burn fossil fuels, and create greenhouse gases and toxic pollutants, that are killing us,” she said.    

Business groups also opposed S198, which would prohibit the state pension funds and annuity funds from investing in the “200 largest publicly traded fossil fuel companies,” and require the funds divest from any such companies in the existing portfolio. 

The divestment should be done “in accordance with sound investment criteria and consistent with their fiduciary obligations,” the bill states. It also gives the director of the State Division of Investment the power to reinvest in fossil fuel companies and funds or continue investing in them if “within a reasonable period of time” the value of the state retirement funds drops to 99.5% or lower of the “hypothetical value had no divestment occurred.” 

Smith rejected the suggestion that the state’s divestment would be of no consequence to big fossil fuel companies that do “trillions of dollars of business.” He said they do listen to “governments and institutions in society that stand up and say, ‘You’re going in the wrong direction.’” 

But Ray Cantor, a lobbyist for the New Jersey Business and Industry Association, said pension fund managers have a fiduciary responsibility to make decisions that generate as high a return as possible. The state should “not be looking to use our pension funds as a lever to enact public policy,” he said. 

Scot Mackey, a lobbyist for the American Petroleum Institute, said the industry is trying to address climate change. Penalizing investment in the industry would penalize the investments “that they’re making in the future, as they try to change and they try to grow into what the future is going to look like,” he said. 

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PJM Stakeholders Open Poll on Proposal to Align Electric and Gas Markets

PJM’s Electric Gas Coordination Senior Task Force has opened a poll on a proposal aimed at aligning components of the RTO’s energy market with gas pipeline operations. 

The joint package sponsored by PJM, Dominion Energy and Gabel Associates would add intraday real-time commitment runs to the day-ahead market ahead of the three gas nomination cycle deadlines and notify gas-fired generators that they are being committed with adequate time for them to nominate for fuel in the subsequent cycle. In turn, generators would be asked to notify PJM if they have procured fuel or expect to do so in time to be scheduled. 

Speaking during a Jan. 30 task force meeting, PJM’s Brian Fitzpatrick said the proposal is focused on improving situational awareness over the status of gas generators and reducing the need for operators to check in with the approximately 300 such resources during emergency conditions. 

“Really it’s about reducing the unknowns and identifying where there are risks,” he said. 

Having multiple commitment periods throughout the day corresponding to the gas nomination cycles would give PJM insights into when resources are likely to be available, such as whether they have obtained fuel for evening peaks. 

Voting on the proposal will be open for around two weeks, and results are expected to be discussed at the task force’s Feb. 29 meeting. This is the second poll the task force has held, following a round in which six packages failed to receive majority support in October. 

The highest vote-getter was a joint proposal sponsored by PJM and Dominion, which would have required gas generators to confirm to PJM that they had procured adequate fuel to meet their day-ahead commitment. It would have also required that resources that had not procured fuel during a PJM cold weather alert verify gas availability with pipeline operators twice a day and reflect any shortages as a forced outage. 

Michael Borgatti, Gabel senior vice president of RTO services and regulatory affairs, said he’s hopeful that the joint proposal can be a compromise between all those previously brought to the task force. 

The revised package now under consideration states that generators should confirm the availability of their fuel supply and reflect that in their parameters, but Fitzpatrick said it would not carry any enforcement or penalties. 

Brock Ondayko, director of RTO operations for AEP Energy, said that even without any specified penalties at PJM, generators that report incorrect information — such as stating that a unit has purchased fuel and then experiencing an interruption in supply — could run into compliance issues with FERC. 

Independent Market Monitor Joe Bowring said the fuel reporting component is vague and would be ineffective at providing true situational awareness without stronger requirements. In particular, he said allowing generators to state that they expect to have fuel available would add too much ambiguity to the process. 

“It is creating false confidence, so I really don’t see the point of this,” he said. “In my view this is potentially worse than not having it. … The straightforward approach is to have a mandatory requirement to report whether a unit has procured gas. Combining the voluntary reporting in the proposal with reporting about what generators expect makes that part meaningless or worse than meaningless. A rule based on a generator’s expectation is an unenforceable rule.” 

Vistra Director of PJM Market Policy Erik Heinle said the deadlines for reporting information to the RTO could distort the gas market if a large number of generators are trying to get contracts in place at the same time. 

Bowring also said that the proposal would be a significant change to PJM’s day-ahead markets that has not included a careful review of how the interaction with markets would work and the likely consequences. 

“Issues including whether the commitment process prior to the day-ahead market would use the same software and have the same objective function have not been addressed. Issues about how market payments and uplift payments would be defined and the treatment of commitments prior to the day-ahead market that carry forward into the next day have not been carefully thought through. The Market Monitor supports increased situational awareness and supports inclusion of offer parameters that are consistent with pipeline rules, but this proposal is being rushed to a vote before important questions have been asked, let alone answered,” Bowring said. 

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Ohio, Pa. Officials Examine PJM Reliability in Joint Session

Ohio and Pennsylvania lawmakers met in Columbus for a hearing on the future reliability of the PJM grid, quizzing RTO and industry insiders on the role states can have in maintaining resource adequacy.

Much of the Feb. 1 discussion centered around the concerns PJM expounded on a year ago in its so-called “4R’s” report (“Resource Retirements, Replacements & Risks”), which laid out a scenario in which a significant number of thermal generators deactivate and take their capacity offline faster than renewables can replace it. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.)

PJM Senior Vice President of Governmental and Member Services Asim Haque — a former chair of the Public Utilities Commission of Ohio — said the RTO has made strides in improving generator performance since December 2022’s Winter Storm Elliott, when 46,124 MW were unable to perform. He pointed to a 16,119-MW peak forced outage rate during the winter storm of mid-January.

Two proposals PJM filed with FERC last year following the Critical Issue Fast Path (CIFP) process aim to further incentivize capacity resources to take the steps necessary to perform during extreme weather and to rework components of the Reliability Pricing Model (RPM) to send the market signals the RTO sees as necessary to address the longer-term resource adequacy concerns at the heart of the 4R’s report. One of those filings (ER24-99) was approved by the commission last week, while an order on the other (ER24-98) is expected Feb. 6. (See related story, FERC Approves 1st PJM Proposal out of CIFP.)

While PJM is adjusting its markets to address the possible imbalance between retirements and new entries, Haque said the majority of the anticipated deactivations through 2030 are because of state and federal policies.

“Part of the reason we’ve been doing this sort of road tour is this concept of avoiding policies that push resources off of the grid until a replacement quantity has been added to the grid. So this is something that we’ve been trying to tout and explain to policymakers across the footprint,” he said, adding that the other side of the coin is finding ways of working with states to speed development of new generation.

ReliabilityFirst President Tim Gallagher said its latest reliability study identified policy decisions as a top risk to the grid for the first time and urged legislators to ensure that changes are designed to leave time for analysis to understand potential ramifications.

“Right now it looks to me like the effort to remove conventional resources from the grid is outpacing our ability to keep up with it. … None of the problems associated with transitioning to a greener grid are unsolvable or insurmountable; they just take time, and they take money. So I think the single biggest thing you can do as policymakers is ask the right questions,” Gallagher said.

Public Utilities Commission of Ohio Chair Jenifer French said PJM’s focus should be on maintaining reliability and a diverse portfolio of generation types to avoid overdependence.

“We must refocus PJM’s capacity market on its basic purpose — resource adequacy and reliability — rather than the promotion of state or federal policy initiatives that undermine that purpose,” she said.

NERC President James Robb said the 1-in-10 reliability target long used in the electric industry is on its way to becoming antiquated as growing electrification decreases consumers’ tolerance for grid outages that may disrupt home heating or electric vehicle charging. As those changes in consumer demand drive load growth not seen in decades, Robb said new risk vectors demand the attention of grid operators and regulators.

The inverter-based resources substituting for coal, gas and nuclear generators raise questions about their ability to provide essential reliability services, such as frequency control, Robb continued. Significant load growth is also occurring rapidly and in regions that have historically had flat load profiles, both because of electrification and energy-intensive industries like data centers. Threats from bad actors also are manifesting, with hackers targeting utilities in ransomware attacks and extremist groups damaging physical infrastructure.

One of the largest obstacles to addressing those risks is constructing new transmission and gas pipelines, Robb said. He noted that the only major interstate power line built in the past 20 years, the 500-kV SunZia line between Arizona and New Mexico, took 17 years to get final construction permits.

“That’s completely out of whack with the pace of change that we’re dealing with. … It’s due to issues such as cost allocation; it’s due to issues such as siting; and it’s due to a range of policy issues that are making it very, very hard to legitimize projects to attract investment,” he said.

Ohio state Sen. Kent Smith (D) said PJM is sounding the alarm on resource adequacy and reliability, but he noted that in its December 2023 Long-term Reliability Assessment, NERC rated the RTO as being at normal risk.

Robb said the level of risk it has seen across the U.S. has been steadily growing to now include elevated concerns with PJM’s neighboring balancing authorities, raising the possibility that those regions will lean on the RTO during emergencies. He added that the 4R’s report looked at a longer horizon than NERC’s annual analysis and predicted that the risks it presented will manifest in assessments released over the next few years.

Pennsylvania state Sen. Gene Yaw (R), chair of the Senate Environmental Resources and Energy Committee, asked what obstacles there are to new resources coming online to meet the growing imbalance between supply and demand.

“PJM has had to get its house in order to ensure that our markets appropriately reflect what we are seeing in this energy transition and incent reliability,” Haque said. “So we’ve done capacity market reform; there’s one more filing that’s outstanding, and it relates to market power mitigation, and in our opinion, the market is being over-mitigated right now.” He added that additional changes are being made to the reserve and regulation markets.

Speaking on the hearing’s second panel of the day, Glen Thomas, president of GT Power Group, said there are also numerous market structures at PJM that are discouraging investment in the RTO’s capacity market. He pointed to FERC’s 2021 approval of a tightened minimum offer price (MOPR) that allowed resources receiving state subsidies to avoid being mitigated to their cost-based offers, a stringent market seller offer cap (MSOC) and Capacity Performance (CP) penalties exceeding $1 billion following Winter Storm Elliott. (See 3rd Circuit Rejects Challenges to PJM MOPR, Affirms Authority over FERC Deadlocks.)

Thomas said comments submitted by the Pennsylvania and Ohio utility commissions were instrumental in supporting the CIFP proposal the commission approved in January and encouraged the states to remain engaged at the federal level, both with FERC and on EPA rule proposals.

Ohio Manufacturers’ Rebuttal

The Ohio Manufacturers’ Association (OMA) questioned PJM’s message that long-term reliability is at risk in a Jan. 31 briefing, raising commissioned analysis of the 4R’s report that suggested that the RTO had not adequately accounted for shifting market signals if resource deactivations accelerate and intermittents fail to keep up.

Go Sustainable Energy CEO John Seryak, who drafted OMA’s rebuttal to PJM’s study, said in such a scenario the capacity market would automatically produce market signals that would incentivize developers to speed up or make investments that allow existing resources to comply with the environmental regulations the RTO predicts may cause their deactivation.

OMA President Ryan Augsburger argued that PJM is overstating reliability risks in a manner that will lead to higher rates for consumers and said repeat tinkering with the capacity market design has led to delays in running Base Residual Auctions, depriving investors of market signals and confidence in the markets.

“While Ohio manufacturers agree that future shortfall risks should be taken seriously, we believe that PJM’s ‘Resource Retirements, Replacement & Risks,’ or 4R’s report, overstates this situation and only caters to the desires of its utility company members to justify expensive new investments that they will pass on to ratepayers, thus exposing manufacturers and others customers to significant new costs,” Augsburger said.

Brad Belden, president of Belden Brick and chair of the OMA Energy Commission, said PJM needs to balance reliability with customer affordability to avoid onerous electric rates that discourage economic growth.

“The OMA-commissioned review of the grid operator, PJM, raises a lot of questions that remain unanswered by PJM,” Belden said. “Their own report showed that new gas and renewable power, along with much of our existing generation, could meet the meets through 2030, even with any plant retirements, but PJM is seeking changes to its markets that could be costly. With plenty of natural gas and renewable energy waiting in line to provide power, we’re not sure why PJM is making costly changes.”

Ohio Consumers’ Counsel Maureen Willis said her office protested the CIFP filings, arguing that they should not be made prior to the next capacity auction and that further understanding is needed to understand the costs they could pose for ratepayers.

“There’s this push by PJM and others to scare lawmakers and other regulatory authorities into acting immediately without actually considering the consequences of their actions or without knowing the costs to consumers,” she said.

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Long-duration Storage Key to Calif. Energy Goals, Report Says

Long-duration energy storage (LDES) will play an essential role in cost-effectively decarbonizing California’s electricity grid, according to a report released by the state’s Energy Commission (CEC) Jan. 29.  

The study, prepared by researchers from Energy+Environmental Economics (E3), Form Energy and University of California, San Diego, explores how LDES can help California meet goals set out in Senate Bill 100, the 2018 law requiring the state to serve all retail electricity load with emissions-free power by 2045.  

Relying on modeling of the CAISO grid, it represents the most in-depth analysis to date of the crucial role the technology will play in California’s transition to renewable energy. 

The report also examines LDES’s ability to reduce air pollution in the Los Angeles Basin, as well as its role in supporting resilience in microgrids.  

Main Findings

The study found that California has made significant progress in its energy transition, with prior studies showing the electric sector could reach 80% or greater decarbonization with existing technologies. But achieving decarbonization and reliability won’t be cheap without innovations in LDES, which could be a viable replacement for the natural gas-fired power plants that are traditionally relied upon for dispatchable capacity to balance renewables and meet grid reliability standards.  

Under a business-as-usual SB 100 scenario, which allows for retainment of all existing gas resources, the study found that deploying 5 GW of LDES could cost-effectively bring CO2 emissions down to 12 million metric tons by 2045. LDES is far more cost-effective with up to 37 GW deployed by 2045 under a zero-emissions scenario that covers in-state emissions and electricity imports.  

Simulations across 35 historic weather years in the Los Angeles Basin case study showed that LDES enables retirement of gas plants in the CAISO system while maintaining reliable grid operation. By 2045, 21 GW of LDES could substitute for all of California’s existing gas plant capacity. Without LDES, the study found that the cost of using other resources to avoid reliance on gas plants increases by up to 87%.  

“Portfolios that retire in-state gas by using LDES were found to achieve cost parity, and in some cases cost savings, relative to those that retain existing in-state gas,” the study found.  

While researchers highlighted that further analysis is needed to evaluate the environmental justice benefits of retiring gas-fueled generation more quickly, they demonstrated that LDES will likely play an important role in cost-effectively maintaining local capacity requirements while reducing the need to rely on emitting resources in disadvantaged communities.  

“In Form’s study of the Los Angeles Basin as an example area, 2 GW of LDES and 1.3 GW of 4-hour lithium-ion storage is found to be the least-cost substitute for gas power plants located in disadvantaged communities, lowering system costs by 3%,” Form Energy said in a brief about the report. “This is the first time that the benefits of LDES to local reliability and environmental justice have been studied in the state, creating a model for how other local reliability areas can be studied in the future.” 

Support for Microgrids

In a case study of microgrids at the University of California, San Diego, the team also found that LDES can support high-reliability microgrids by pairing with other distributed energy resources to deliver 48-hour resilience capability, also known as “islanding,” and protecting against outages.  

However, LDES-supported microgrids may not be cost-effective. The study found that the customer value of lost load needed to justify its use ranged between $5-18 kWh for small campus buildings. Some larger buildings, though, demonstrated a negative value of lost load, showing that some microgrids improve reliability while reducing costs.  

Goals

In addition to demonstrating the distinct value LDES will bring to California’s energy transition, the study highlighted the need for modeling tools and approaches that can continue to accurately capture the value of LDES in future portfolio planning. It also emphasized the importance of optimizing resource needs with hourly time resolution across a full year and in varying weather scenarios.  

“By using these methodologies, grid planners can proactively identify resources that electric markets may not yet be fully valuing,” Form’s brief said. “From there, policy initiatives can be designed to ensure these resources are able to rapidly proliferate and deliver savings to the electric grid.” 

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NEPOOL Participants Committee Briefs: Feb. 1, 2024

BOSTON — New England power system emissions decreased by about 3.6% in 2023 compared with 2022, according to the underlying data from ISO-NE COO Vamsi Chadalavada’s monthly report to the NEPOOL Participants Committee.  

Natural gas emissions increased by about 3% in 2023, accounting for about 75% of all power system emissions. Oil emissions dropped drastically, ending the year at about 17% of their 2022 levels. Coal emissions also declined, decreasing by about 43%. 

Based on data through Jan. 24, Chadalavada said the energy market value for January totaled $712 million, an increase from $552 million in January 2023. He noted that the monthly peak load was 18,431 MW.  

ISO-NE annual CO2 emission estimates in million metric tons | ISO-NE

Capacity Market Recommendation

The meeting materials indicated ISO-NE has decided to recommend that it transition its Forward Capacity Market to a prompt and seasonal capacity market, which would reduce the time between the auction and the capacity commitment period (CCP), while splitting the annual CCP into seasonal periods.  

ISO-NE noted that its Board of Directors “concurred with management’s recommendation to transition to a prompt, seasonal capacity market, which it will discuss next with stakeholders.” 

At the NEPOOL Markets Committee on Feb. 7, ISO-NE will propose a two-year delay of Forward Capacity Auction 19 “to allow for time to design a prompt and seasonal market for CCP 19.” 

Votes

The PC voted to approve ISO-NE’s proposal to lower the Forward Reserve Market (FRM) offer cap from $9,000/MW-month to $7,100/MW-month and delay the publication of data from the auction. These changes were initiated in response to concerns raised by the ISO-NE Internal Market Monitor about market power in the FRM.  

The FRM is designed to procure reserve capacity and is held twice annually. In March of 2025, ISO-NE will replace the FRM with a new day-ahead ancillary services market. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.) 

The RTO initially proposed lowering the cap to $6,400/MW-month but adjusted its proposal to $7,100/MW-month following stakeholder feedback and a $7,200/MW-month counterproposal from LS Power that was supported by a vote in the Markets Committee.  

The PC also voted to approve changes to its interconnection planning procedures to improve the modeling of inverter-based resources and “update system modeling assumptions to align with the operating conditions expected with the clean energy transition.” 

The committee also approved tariff changes to assign responsibility to distributed energy resource aggregators to submit their aggregation’s metering information.

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FERC Grants AEP Utilities Waiver of Capacity Obligation

FERC on Jan. 31 granted American Electric Power waivers to alter the capacity obligation calculation for four of its vertically integrated utilities in PJM to not include load growth outside their territories (ER24-545).

In its Dec. 4 request, the company said its AEP Ohio affiliate, which participates in PJM’s Reliability Pricing Model (RPM), had submitted a forecast large load addition of about 1,860 MW largely attributed to data centers expected to be constructed in its footprint. Under PJM’s approach to allocating capacity obligations, AEP said the majority of the responsibility to procure the capacity to serve that load would fall on other affiliated utilities in the AEP transmission zone that participate in the fixed resource requirement (FRR) alternative to RPM. The company estimated that 1,039 MW of the increase would be allocated to Appalachian Power, Indiana Michigan Power, Kentucky Power and Wheeling Power.

“The AEP FRR entities seek this waiver so the forecasted peak load increase associated with the projected large load additions will appropriately remain in the PJM region reliability requirements addressed by the BRA [Base Residual Auction] for delivery year 2025/2026, instead of being shifted to the AEP FRR entities. The waiver will allow the AEP FRR entities’ customers to avoid rate impacts caused by the procurement of capacity not needed to serve them,” the company said in its request.

The company asked permission to excise the base zonal FRR scaling factor from the calculation of the FRR utilities’ capacity obligations, resulting in an equation that multiplies the obligation peak load by the forecast pool requirement (FPR). That would assign the entirety of the capacity obligation for the 1,860 MW to the electric distribution companies within the AEP zone.

FERC said in its order that the waiver “will allow the AEP FRR entities to avoid procuring unneeded capacity for purposes of its FRR capacity plan for the 2025/2026 delivery year.”

PJM commented that so long as the forecast large load additions are entirely within EDCs participating in the RPM, the waiver has merit, but it requested that the commission confine its approval to the issue at hand, as stakeholders are considering changes to how capacity obligations associated with forecast large load additions are split between FRR and RPM entities within the same transmission zone. The problem statement stakeholders are considering, jointly brought by AEP and Dominion Energy, states that high load industries are resulting in concentrated pockets of growth, often within single EDC regions.

“There is stakeholder support for revising the [Reliability Assurance Agreement] to eliminate this impact of the base zonal FRR scaling factor, which seems to be a relic of a time in which increases to load forecasts were more generally experienced across a transmission zone, as opposed to being concentrated within a single EDC’s service area,” AEP argued in its request.

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BPA Targets August for Draft Day-ahead Market Decision

The Bonneville Power Administration plans to issue a draft decision on its day-ahead market participation in August, followed by a final decision in November, the federal power marketing agency told stakeholders Feb. 1. 

The new timeline represents a shift from the one BPA initially set out last July when it launched a series of workshops to explore its potential participation in either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+ offering. 

At that time, the agency had targeted February 2024 for the release of a “policy direction” including a decision on whether to join any day-ahead market and a “leaning” on which of the markets it would likely choose. 

While the exact meanings of “policy direction” and “leaning” have been open questions for months, the expected content of both became somewhat clearer last week.  

BPA told stakeholders during its Feb. 1 day-ahead markets (DAM) workshop that it now plans to issue a “policy letter” in early April that will provide a “light touch” on the agency’s business case and legal authority to participate in a day-ahead market.  

The letter also will contain a “description of BPA’s strategic vision related to DAMs, including a staff recommendation on whether to pursue participation and which DAM may be the best fit for BPA at this time,” BPA said. 

In an emailed response to questions from RTO Insider, BPA spokesperson Doug Johnson said the letter “will provide a staff recommendation with an initial policy direction as to whether BPA sees value in joining a day-ahead market and, if so, which DAM option best meets its principles. BPA will include a brief description of its legal authority to participate, an initial evaluation of the value proposition and a discussion of other factors supporting its staff leaning.” 

BPA’s revised timeline now calls for the release of a “draft policy” on day-ahead market participation at the end of August, which will cover the agency’s business case and legal authority regarding participation. The draft will also “either validate BPA’s initial staff recommendation” on a market choice or “lay out an alternative direction,” the agency said. 

BPA has tentatively scheduled a public workshop on the draft policy for Sept. 19. It then plans to issue a final policy and record of decision in November.  

In the meantime, the agency said it will continue to engage with stakeholders on the day-ahead market issue. Another DAM workshop will be held in the first week of May to discuss the April policy letter, the staff recommendation and any comments received by the agency. Additional workshops are scheduled for June 5 and Aug. 6.   

Competing Concerns

The change in BPA’s timeline comes in response to the tangle of issues the agency confronts as it moves toward a decision. 

One of the thorniest relates to BPA’s “preference customers,” made up of publicly owned utilities across the Northwest, who are concerned that the agency’s deeper involvement in an organized market could compromise their rights to access low-cost power from the federal Columbia River hydroelectric system. They are seeking greater guarantees that protect their interests before BPA decides to join any day-ahead market. 

Another key issue relates to BPA’s choice of a market as CAISO and SPP compete for participants in their respective day-ahead offerings. BPA’s decision carries significant weight because it operates about 70% of the transmission in the Northwest and is the region’s largest power provider. 

It’s for that reason the agency has been under significant pressure on multiple fronts to slow down its decision-making process.  

At BPA’s second DAM workshop last September, stakeholders who support a single market for the West based on CAISO’s platform complained that the agency’s initial timeline was too aggressive. They were concerned BPA’s leaning effectively would constitute a final decision — and that the agency already was favoring Markets+.  

Key critics of the faster timeline include the environmental and consumer group Northwest Energy Coalition, as well as state energy officials from Oregon and Washington. They contend BPA should delay issuing a leaning until developments play out around the West-Wide Governance Pathways Initiative, a state-led effort to create the framework for an independent Western RTO that includes CAISO while addressing concerns about the ISO’s governance. In comments filed with BPA in November, municipal utility Seattle City Light questioned why the agency was not directly participating in the initiative given that it was designed to address many of BPA’s concerns related to CAISO governance. 

Others, including some public power representatives, have said a quick decision was necessary to ensure the agency exercised sufficient clout to shape market developments in the broader West. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.) 

BPA appeared to be touching the brakes on a decision during its November DAM workshop, when it told stakeholders it still would issue a policy direction during the first quarter of 2024, but that the content would change to cover the agency’s statutory authority to join a day-ahead market while also including a market leaning.  

During that meeting, Russ Mantifel, BPA director of market initiatives, acknowledged the agency still had “limited information” on which to base a market decision, saying the timing was “up in the air” in light of uncertainties around tariff timelines for EDAM and Markets+. (See Region Still Split as BPA Approaches Day-ahead Market Decision.) 

Since then, FERC has approved CAISO’s EDAM tariff and SPP has pushed back the schedule of its Markets+ tariff filing from early February. The Arkansas-based RTO now plans to put the tariff to a board vote in late March and hopes to win FERC approval within nine months, which then would allow the RTO to begin Phase II of the market’s development. (See SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)  

‘Sufficient Information’

BPA on Feb. 1 rebuffed concerns by Oregon and Washington state agencies that the agency still lacks the information needed to support a leaning. In a slide presented during the workshop, the agency affirmed that it “will issue its initial staff recommendation regarding Bonneville’s policy direction on potential DAM participation in a letter this spring and feels it has sufficient information to do so.” 

BPA told RTO Insider the staff recommendation “will inform customers and stakeholders about its policy leaning to aid in their assessments of the changing energy landscape, provide considerations regarding potential DAM participation, inform customer product choices and operational goals, and invite discussion on other salient issues that BPA should consider when developing a more formal policy direction and issuing a record of decision in late 2024.  

“Any decision to join a DAM would be dependent on BPA rate and tariff proceedings and contract updates,” it said. 

BPA said it continues to monitor developments taking shape across the West, including efforts around the Pathways Initiative. 

“BPA staff have been assessing CAISO’s EDAM and SPP’s Market+ day-ahead market designs, public power concerns and support regarding potential participation, and considerations regarding issues such as carbon emissions reduction goals, continuing to meet environment, fish and wildlife stewardship obligations, maintaining close relationships with states and tribes, and providing service in the most economical, efficient and reliable manner,” Johnson said. “BPA has interfaced with other potential DAM participants to understand potential market footprints.”

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SPP Directors Pleased with Progress of Markets+ Tariff

SPP’s two independent directors with backgrounds in the Western Interconnection both expressed relief and optimism at the grid operator’s collaborative efforts with stakeholders to develop Markets+ in the West.

The comments came during a conference call Feb. 2 with members of the Markets+ Participant Executive Committee (MPEC) and the Markets+ State Committee (MSC).

“Honestly, a year ago, I was probably a bit skeptical about the potential for being in this position of essentially the major tariff issues being resolved in less than a year,” said Steve Wright, a former Bonneville Power Administration administrator and CEO. “The progress is really amazing. An incredible array of folks have come to the table and found compromise on what have been intractable issues in the West in the past.”

John Cupparo, a former officer with PacifiCorp and experienced in several other western initiatives, pointed to stakeholder approval rates in the 90s on votes for tariff language and other issues and lack of appeals to decisions already made as evidence of a job well done.

“From my perspective, this is truly reflective of a market for the West, designed by the West and governed by the West,” he said.

Along with director Liz Moore, Wright and Cupparo constitute the Interim Markets+ Independent Panel (IMIP), the temporary body overseeing the day-ahead market’s development. The directors listened to several reports on last month’s MPEC meeting and approved 15 pieces of language related to the Markets+ tariff and its attachments.

The IMIP also approved modifications to the independent sector’s voting structure, previously approved by the MPEC. (See “Independent Sector Changes,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)

The primary remaining sticking point is what’s been called a “gap” with the accuracy of information to be shared with SPP’s Market Monitoring Unit under FERC’s duty of candor requirements. SPP, the MSC, the MMU and western legal groups are all involved in resolving the issue.

MSC member Ann Rendahl, a commissioner with the Washington Utilities and Transportation Commission, said “much” progress has been made since the January MPEC meeting. The various entities involved met the week after MPEC and are planning to resume discussions this week.

“We see this moving in a direction that will address the outstanding concern that we have. We’re optimistic that the language can be worked through the Markets+ process in the coming weeks and adopted into the tariff,” Rendahl said.

“Everyone engaged in this exercise is invested in building a robust, transparent market that earns the trust of parties throughout the West,” she added. “We’re all well aware and understand the long history of market development in the West. There’s considerable scar tissue in the West surrounding prior experience with significant adverse customer-rate impacts associated with price and market manipulation.”

A reference, perhaps, to the western energy crisis of 2001 instigated by Enron in California, and hopefully, soon to be forgotten.

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MISO to Relax Commercial Operation Deadlines in Interconnection Queue

MISO plans to revise its rules around commercial operation dates to allow interconnection customers to begin operating about a decade after they first enter the queue. 

MISO’s Brady Mann told stakeholders attending a Jan. 30 Interconnection Process Working Group that the RTO is considering working a few extra years into queue deadlines, recognizing that supply chain squeezes have impeded projects. 

That starts with MISO drafting rules specifying that interconnection customers must select a date up to five years on the horizon for their generation projects to reach commercial operation when entering the queue. After that, MISO said it will continue to employ a three-year extension of the original commercial operation date in generator interconnection agreements (GIAs). Additionally, the RTO will allow transmission owners the option to request an extra two-year extension of the in-service date during GIA negotiations. MISO’s current tariff language doesn’t allow transmission owners to request extensions to complete network upgrades for generation projects during negotiations. 

Finally, Mann said MISO will allow for 180 days between a generation project’s in-service date and the commercial operation date to account for delays transmission owners might encounter in constructing network upgrades.  

The new package of rules could be included in the MISO tariff and business practice manuals and could apply to projects that entered the queue beginning in 2020.  

Mann said MISO probably will rely on targeted FERC waivers of tariff provisions for the 2018 and 2019 cycle of queue projects that have been especially hard-hit by supply chain woes and stalled in coming online.   

MISO plans to make a tariff filing later this year after it weighs stakeholder opinions, which it solicited at the meeting. The RTO told stakeholders last year it would consider extending deadlines after EDP Renewables pointed out that generation developers increasingly are exceeding MISO’s allotted six-years-from-originally-planned commercial operation and having to turn to FERC for waivers. (See MISO Somewhat Open to COD Allowances in Interconnection Queue Rules.)  

Current MISO policy requires interconnection customers’ GIAs to contain a commercial operation date that’s within three years of the date originally requested in their queue applications. It also allows an up-to-three-year extension of the commercial operation date in initial GIAs after execution. When customers can’t meet either, MISO can terminate the GIA, causing generator developers to lose their place in line unless they can secure a waiver of their commercial operation dates from FERC.