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November 17, 2024

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New California Energy, Climate Laws Go Live

A half-dozen new climate and energy laws took effect in California on Jan. 1, including measures to promote carbon capture and sequestration, establish emissions reduction and clean energy targets, and instruct the state’s three major energy agencies to expand their long-term generation and transmission planning horizons.

On the clean energy front, Senate Bill 1020 establishes new state goals of using 90% carbon-free electricity by 2035 and 95% by 2040 as steps on the way to supplying retail customers with 100% clean energy by 2045, as required by 2018’s Senate Bill 100. The bill was developed last year by the Senate Climate Working Group.

“Senate Bill 1020 is our collective victory in equipping California to meet the urgent challenges of climate change, adaptation and resiliency through an equitable lens,” Sen. John Laird, who authored the measure, said in a news release when Gov. Gavin Newsom signed it in September. “We cannot afford to wait for a better time for progress, and the accelerated goals established in SB 1020 reflect this urgency.”

Another key measure, Assembly Bill 1279, codified a 2018 executive order by former governor Jerry Brown that originated the state’s goal of achieving carbon neutrality by 2045. The legislation also requires the state to reduce greenhouse gas emissions at least 85% below 1990 levels by 2045 and instructs the California Air Resources Board (CARB) to report to the legislature on the “feasibility and tradeoffs” of achieving the bill’s goals.

Carbon Capture

Several laws that took effect in the new year aim to advance carbon capture and sequestration (CCS) as viable means of reducing greenhouse gasses.

Senate Bill 905 directs CARB to establish a regulatory framework for carbon capture and storage technologies to prevent CO2 from entering the atmosphere and to trap it underground. In its 2022 scoping plan, CARB said the state should use the technologies as a way to meet emission reduction goals, though no such projects currently exist in California.

“Carbon capture and sequestration will be a necessary tool to reduce GHG emissions and mitigate climate change while minimizing leakage and minimizing emissions where no technological alternatives may exist,” the CARB plan said.

The measure also requires CARB to develop a streamlined permitting process by 2025 that evaluates seismic, environmental and air-quality risks, and to create a public database that tracks the development of CCS projects statewide.

Assembly Bill 1757 tasks the state Natural Resources Agency with establishing ambitious carbon sequestration targets for “natural and working lands” by Jan. 1, 2024.

“The state’s forests, agricultural lands, rangelands, wetlands, oceans, and other natural and working landscapes define the beauty and well-being of our state, but tragically are suffering increasing degradation caused by a changing climate,” the measure says.

The Natural Resources Agency has until Jan. 1, 2024, to create a plan with specific CO2 reduction goals for 2030, 2038 and 2045 and to establish an expert advisory committee to “inform and review modeling and analyses for natural and working lands [and] to advise state agencies on implementation strategies.”

In addition, the act requires CARB to determine “standard methods for state agencies to consistently track greenhouse gas emissions and reductions, carbon sequestration, and, where feasible and in consultation with the Natural Resources Agency and the Department of Food and Agriculture, additional benefits from natural and working lands over time.”

Senate Bill 1314 prohibits captured CO2 from being injected into oil wells for “enhanced oil recovery,” or EOR, as a way to extract remaining oil.

EOR isn’t widely used in California, but injection of CO2 and other gasses “accounts for nearly 60% of EOR production in the United States,” according to the U.S. Department of Energy. Increased carbon capture could expand the practice, it said.  

“The legislature finds and declares that the purpose of carbon capture [and sequestration] technologies … is to facilitate the transition to a carbon-neutral society and not to facilitate continued dependence upon fossil fuel production,” the bill says.  

Transmission Planning

Several transmission planning bills faltered or were heavily water down in 2022.

One that passed mostly intact was SB 887. It directs CAISO, the California Public Utilities Commission and the state Energy Commission to expand their generation and transmission planning horizons from the current 10 years to “at least 15 years … to ensure adequate lead time for [CAISO] to analyze and approve transmission development and for the permitting and construction of the approved facilities.”

CAISO already performs a 20-year transmission outlook, but it is a long-term conceptual plan of grid needs, including out-of-state projects, intended to complement but not replace the ISO’s 10-year transmission planning process, which concerns only in-state projects.

Becker’s bill instructed CAISO to identify “the highest priority transmission facilities that are needed to allow for reduced reliance on [fossil fuel] resources in transmission-constrained urban areas by delivering renewable energy resources or zero-carbon resources that are expected to be developed by 2035 into those areas.”

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NYISO Stakeholders Still Concerned About DER Participation Model

NYISO on Friday presented the Installed Capacity/Market Issues Working Group (ICAP/MIWG) with draft revisions to its distributed energy resource participation model that included feedback, though stakeholders continued to express concern over what they said is a lack of clarity.

NYISO has identified several concepts within the FERC-approved model that it says require revisions to both clarify and better align them with ongoing software updates, including how utilities share data with the ISO, removing previous unused models and adjusting certain calculations. Harris Eisenhardt, NYISO market design specialist, told stakeholders that in response to stakeholder feedback, the ISO attempted to clarify the types of changes to an existing DER or group of DERs that would result in a supplemental review.

Stakeholders were still confused, however, about how aggregation makeups would be adjusted over time and how those changes would impact utilities’ construction costs and information-sharing. Mike Cadwalader, president at Atlantic Economics, summarized the concerns by saying that NYISO has made “an improvement but is not there yet.”

Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, said NYISO needs to be specific about the types of DER changes that qualify for review, as utilities “may not realize that by making a change, they’re triggering a whole review process.”

Matt Cinadr, a power systems operations specialist with The E Cubed Co., and Mark Younger, president of Hudson Energy Economics, both expressed concern about how invertor-based resources would be treated in the new model. Cinadr said, “These things need to be widely understood as we move forward with inverter-based resources” because the unknowns around them “will cause a lot of people a lot of headaches.”

Stakeholders were also concerned about the lack of details or timeline of the transition to the new model. Greg Campbell, senior attorney with NYISO, sought to alleviate by saying that the ISO “plans on including in its filing what the transition process will be” and that “timing and transition information will be included.”

NYISO will seek approval of the revisions at the Feb. 15 Business Issues Committee meeting and the Feb. 22 Management Committee meeting. It then anticipates starting the DER transition process in the third quarter of 2023.

Julia Popova, NRG Energy’s manager of regulatory affairs, said it would be important for NYISO to include any “hardwired deadlines” in their filing, as this would give stakeholders a better sense of how the transition will progress.

Peter Fuller, an energy consultant who works with NRG, summarized the mood of the room, saying, “It’s January, and DER is supposed to go live later this year,” so NYISO “needs to figure out how they’re going to do this.”

Final LCR Results

Final 2023-2024 LCR Results (NYISO) Content.jpgFinal 2023-2024 LCR Results | NYISO

 

NYISO also presented the ICAP/MIWG with results for their updated locational minimum installed capacity requirements (LCRs). They showed that Zone K’s (Long Island, excluding Brooklyn and Queens) LCR increased by 0.1% to a total of 105.2%, raising the total New York Control Area’s Installed Reserve Margin (IRM) by 0.1% to 20%.

The ISO will present the final LCR results at the Jan. 23 Operating Committee meeting and seek stakeholder approval.

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NY Utilities Propose Plan to Coordinate Decarbonization Efforts

A group of New York utilities last month jointly filed a proposed framework designed to “facilitate the development of a fully decarbonized electric system” in the state by improving coordination among stakeholders.

The seven utilities submitted the Coordinated Grid Planning Process (CGPP) proposal to the Public Service Commission (PSC) on Dec. 27 to ensure that “work on planning and developing the infrastructure needed to support the clean energy resources to meet the milestones stipulated in the [Climate Leadership and Community Protection Act] can begin without delay.”

The utilities include Central Hudson Gas & Electric, Consolidated Edison, Long Island Power Authority, Niagara Mohawk Power/National Grid, New York State Electric & Gas, Orange & Rockland Utilities, and Rochester Gas and Electric.

The proposal envisions a 20-year planning horizon that includes “a repeating three-year process with approximately two years for a system study followed by Commission review,” which will identify both “the electric grid expansions that can aid in unlocking renewable generation capacity and provide energy headroom” and “opportunities for expansion of the bulk transmission system to advance CLCPA objectives.”

This proposal is the product of a multiyear effort that involved numerous iterations and revisions and has been seen as critical to New York’s energy goals by aligning stakeholders, driving consistency between CLCPA-based studies, and informing market policymakers. (See NY Officials, Stakeholders Discuss Utilities’ Tx Planning Process Proposal.)

The CGPP would be coordinated among various stakeholders, such as NYISO, individual utilities and consumers, who will be represented by a proposed Energy Policy Planning Advisory Council (EPPAC).

The EPPAC is intended to serve as an independent stakeholder group that advises “utilities’ system planners on the development of a set of generation build-out scenarios.” It will also be responsible for reviewing the final CGPP report before it is submitted to the PSC for approval.

The utilities said the EPPAC is intended to “ensure stakeholder representation remains a strong and constructive component” of decarbonization efforts and asked the PSC to “provide guidance concerning the recovery of reasonable costs that will be incurred” throughout the CGPP’s stages.

CGPP Stages

Each CGPP cycle would be broken into six, overlapping stages, with the first cycle anticipated to start in mid-2023.

The plan’s supporters foresee that the conclusion of each cycle will produce an “efficient and orderly system expansion that builds on prior assessments and eliminates ambiguity regarding project status in subsequent CGPP cycles.”

The sequenced stages are intended to give the PSC the opportunity to recommend local transmission and distribution (LT&D) projects mid-cycle and identify whether a public policy transmission need (PPTN) process should continue or a new one be initiated.

The first stage consists of a data collection and coordination process in which “utilities and the EPPAC will review and, as necessary, enhance the scope of the upcoming planning cycle,” as well as “determine the assumed zonal allocation for future distributed energy resource (DER) development.”

Stage one will also allow utilities to “run the capacity expansion model for up to three scenarios with the potential for several sensitivities on the selected scenarios,” which would then be shared with the EPPAC to identify “three generation build-out plans selected from the three initial scenario cases.”

In stage two, utilities will use the three scenarios developed by the EPPCA to “develop detailed short circuit and power flow models that will be used in subsequent CGPP stages to assess local transmission systems.”

Stage three consists of an assessment in which utilities evaluate local conditions to determine whether LT&D system upgrades “are necessary to accommodate the integration of DER and utility scale generation resources.”

During stage four, utilities will review the current portfolio of projects to ensure no unintended impacts on the grid, though the report stresses that the CGPP review would not replace NYISO-administered interconnection process requirements.

Stage five includes a least cost planning assessment in which utilities “identify a portfolio of LT&D and bulk projects that will facilitate the achievement of the State’s policy objectives at the least cost to customers.”

The last stage sees development of the final CGPP, which identifies and recommends “projects that were found to be beneficial in the least cost planning assessment” and are “needed to ensure the timely and cost-effective attainment of CLCPA policy goals.”

At the end of each CGPP cycle, the PSC will review the final report and vote on whether to approve recommended LT&D projects. Utilities will then have 30 days to initiate the next cycle.

CGPP reports approved by the PSC will be included in the NYISO planning process and describe the benefits of pursuing a bulk solution to public policy transmission needs.

NYISO Impact

The utilities initially developed the CGPP framework in collaboration with NYISO and expect it to be “complementary to and, where applicable, coordinated with NYISO comprehensive system planning processes,” according to the plan.

ISO representatives will be included on the EPPAC, along with other state agencies, and they will “act as a technical consultant to stakeholders” by “assessing system limitations and developing the optimal portfolio of solutions.”

Furthermore, the first CGPP cycle will use existing NYISO databases, such as Gold Book forecasts, and any project identified through the PPTN process will be made available for NYISO to consider for inclusion in planning.

Opinions and Comments

The CGPP “stems out of a recognition of the need for infrastructure buildout in order for the electric system to achieve Climate Leadership and Community Protection Act (CLCPA) goals,” Ryan Hawthorne, vice president of electrical engineering and operations at Central Hudson Gas & Electric, said in email to RTO Insider.

Hawthorne said “the CGPP is meant to create an integrated planning process to identify local transmission and distribution needed to support these goals, while working in concert with existing planning processes (such as bulk transmission solutions through the NYISO).”

“The state of our current position is a lack of integrated system planning, and the CGPP is there to help close that gap in order to plan optimal solutions to meet growing interconnection needs,” he said

“What is being proposed is a very smart process,” Paul Hines, vice president of power systems at EnergyHub, said in an interview. As power grids become increasingly “messy things” because of an influx of new technologies, it becomes critical for utilities to have “careful planning processes that maintain reliability,” he said.

Hines said he was encouraged by the CGPP’s 20-year planning horizon, given the need to consider the long-term perspective of how distributed resources will change the “physics of how the grid operates.”

But Hines was also wary of the GGPP’s focus on bulk grid assets, despite the growing relevance and value of distributed assets, such as behind-the-meter solar and distributed batteries. He said it is “important to advance the modeling of these distributed assets.”

Should stakeholders discover that current modelling systems are inadequate or antiquated, they should push each other to “advance the modeling of these assets” because these resources will become a growing portion of the state’s grid, he said.

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Ohio Law Amended to Declare Natural Gas a Form of ‘Green Energy’

Ohio Gov. Mike DeWine late Friday signed legislation declaring natural gas a form of “green energy” and requiring state agencies to negotiate with gas and oil developers that want to drill laterally under state properties, including state parks.

The declaration making fossil gas “green” starts by defining green energy as “any energy generated by using an energy resource that does one or more of the following: releases reduced air pollutants, thereby reducing cumulative air emissions, [and] is more sustainable and reliable relative to some fossil fuels.”

The change was among five unrelated amendments inserted in the last days of 2022 into a bill regulating the state’s poultry industry.

H.B. 507 had wide bipartisan support in both the House of Representatives and Senate when introduced and approved months earlier. Democrats withdrew their support of the bill in December when the amendments were added in a Senate committee, immediately approved by Republican majorities in the Senate and sent to the House for the same treatment.

Declaring natural gas green has been a goal of The Empowerment Alliance, an anonymously funded 501(c)(4) nonprofit founded in 2019 with Ohio roots. TEA lobbied state lawmakers, arguing that defining natural gas as green is a way to oppose the Biden administration’s efforts to champion renewable energy technologies while ignoring the gas industry’s role in reducing carbon and other emissions over the last decade by replacing coal. A spokesman said TEA has plans to lobby lawmakers in other states.

In Ohio, TEA has also lobbied county officials in rural counties to declare gas as green. And handful of county commissions adopted such resolutions, though the Ohio Department of Natural Resources (ODNR), not local governments, regulates the oil and gas industry, including permits to drill.

In contrast, changes in state law a year ago reduced the authority of the Ohio Power Siting Board over wind and solar projects by giving county commissioners the final say on every wind and solar project and giving them the authority to declare their county off-limits to any solar and wind development.

A second amendment to H.B. 507, proposed by the Ohio Oil and Gas Association and immediately opposed by environmental groups, requires state agencies to negotiate leases with oil and gas developers that want to drill laterally under state property to access oil and gas.

State agencies have had the authority to negotiate such leases with ODNR’s Oil and Gas Land Management Commission but have never reached an agreement on a specific project.

The amendment does not give oil and gas developers the right to move drilling rigs and shale fracturing equipment onto state land. Ohio shale gas wells typically begin with a vertical well up to 8,000 feet deep before branching into lateral wells drilled 1 to 2 miles through shale rock, which is later fractured with liquids under high pressure, releasing the gas.

In signing H.B. 507, DeWine did not address the issue in the bill’s declaration making fossil gas green. And he downplayed the significance of the language requiring state agencies to negotiate gas and oil leases.

“I believe the amendments in House Bill 507 do not fundamentally change the criteria and processes established by the Ohio General Assembly in 2011 that first established the policy of leasing mineral rights under state parks and lands,” he said in a statement issued at the close of business Friday.

“In addition, I am instructing the director of the Department of Natural Resources to continue to follow the processes first established by the General Assembly in 2011 in this area. This includes continuing my administration’s policy of prohibiting any new surface use access in our state parks.”

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NJ Retools Electric MHD Truck Charger Proposal

A revised version of the New Jersey Board of Public Utilities (BPU) straw proposal designed to stimulate the development of chargers for medium- and heavy-duty (MHD) electric trucks would provide extra support for private fleets that put chargers in overburdened communities but would also place greater demands on the fleets.

The new proposal, which is scheduled for a public hearing on Jan. 17, seeks to “refine” the original package issued in June 2021 with several enhancements. Some were triggered by stakeholder arguments in a series of public hearings in August and September 2021 that with so many trucks working in and around overburdened communities, the BPU would need to offer more benefits to private fleets to get enough to act and significantly cut emissions in those areas.

The original proposal offered limited assistance to private fleets, mainly technical help provided by electric distribution companies. It focused on supporting the development of charging sites in overburdened areas that were open to the public.

The new package makes a private fleet eligible for incentives of up to 100% of the cost of “make ready” work — the pre-wiring of electrical infrastructure at a parking space for future installation of a charger — in overburdened areas. To receive the full subsidy, the fleet charging depot must be located in an overburdened community and must displace existing fossil-fueled vehicles rather than adding new electric vehicles to an existing fleet.

The fleet also must agree to participate in a “managed charging,” which requires it to charge vehicles in off-peak periods, generally overnight, to help reduce the load on the grid.

Legacy of Disinvestment

The MHD charger proposal is part of the state’s effort to cut emissions in its largest polluting sector, transportation, which accounts for about 42% of carbon emissions in the state. Long- and short-haul single unit and combination trucks account for 18% of the greenhouse gas emissions from road vehicles, with another 43% generated by light commercial and passenger trucks, according to the proposal.

At present, electric vehicles account for only a tiny number of the state’s 500,000 MHD trucks, which are major emissions contributors and are especially problematic to communities located near freight corridors, warehouses, distribution centers and ports.

The proposal says that although MHD trucks and buses account for only 4% of the vehicles on the road in New Jersey, they contribute nearly 25% of greenhouse gas emissions.

Gov. Phil Murphy wants the state to reach 100% clean energy by 2050, and the state’s 2019 Energy Master Plan assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.

“The physical and monetary costs of emissions in overburdened municipalities, particularly in urban settings, require ratepayer investment to ensure that EV adoption’s positive impacts are distributed equitably cross the state,” according to the proposal, which was released Dec. 22.

It adds that “staff is convinced that partial socialization of private fleet depots located in or primarily operating in overburdened municipalities is critical to meeting the governor’s commitment to improving environmental conditions in the communities struggling under the legacy of disinvestment and discrimination.”

The proposal does not require that a fleet depot to be located in the overburdened community to be eligible for benefits under the proposal. But if it isn’t, the fleet needs to “primarily operate” there, a phrase that has still to be defined but could include the fleet’s trucks driving a large portion of their mileage in the area, according to the proposal. In example, it cites the definition in the Zero-Emission Incentive Program (ZIP), which is run by the New Jersey Economic Development Authority (EDA) and awards purchase subsidies for light and medium trucks that in some circumstances hinge on the truck doing up to 50% of its miles in overburdened communities.

In another addition to the earlier proposal, the new package makes sites that install chargers higher than 500 kW, sometimes known as “ultra-fast” chargers, eligible to receive technical assistance from utility companies, who could then charge the cost to ratepayers. The earlier proposal allowed the utilities to provide technical assistance only to public and private fleets.

The assistance provided by the utilities is expected to range from picking site charging locations to planning for fleet and charging growth and determining “when, and if, additional grid support is needed,” according to the proposal.

The BPU straw proposal, in both the initial and revised forms, envisions private developers and investors installing, owning and operating EV service equipment and marketing the sites to customers. Utilities would help wire and provide the backbone infrastructure necessary but would not be able to own chargers developed under the program, except in certain circumstances, mostly when no other developer steps forward.

The proposal drew criticism from several fronts on its release. At one hearing, Zachary Kahn, senior policy adviser for Tesla, argued that the private fleets deserved more support because they were already making a serious investment in buying electric trucks and had shown they clearly had “significant skin in the game.”

An attorney for the Sierra Club, Zachary Fabish, said that regardless of whether a charger is private or publicly accessible, it would make the same contribution to reducing emissions and that is essential to combating climate change. (See NJ Electric Truck Rules Face Many Questions.)

In the latest proposal, the BPU says it is working to “define the appropriate level of ratepayer investment in this sector.”

“Many of the issues that this straw proposal seeks to explore include questions about who should construct, own, operate and pay for the MHD network necessary to make New Jersey a national leader in the adoption of electrified MHD fleets and the buildout of an MHD EV ecosystem,” the proposal states.

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Oregon Report Calls for Greater Heavy-duty EV Incentives

When it comes to zero-emission truck incentive programs, Oregon stakeholders want to see a program similar to California’s popular HVIP, and they recommend keeping incentive programs consistent along the West Coast.

Those were some of the findings of a new report from the Oregon Department of Environmental Quality and the state Department of Transportation. The report, “Incentives to Support the Transition to Zero Emissions for Medium- and Heavy-Duty Sectors in Oregon,” was prepared in response to direction from the state legislature.

The report found that current incentives are not enough to promote a rapid transition to zero-emission trucks.

“State and federal grant programs are underfunded, too narrow in scope or both,” ODOT’s Climate Office said in summarizing the report’s key takeaways. “New programs must be flexible and established quickly.”

A variety of incentives are needed for zero-emission vehicles alone, infrastructure, or a combination of vehicles and infrastructure, the report said. In addition, federal, state and utility incentive programs should work together so that the incentives can be “stacked.”

And equity should be a priority, the report said. Incentive programs should earmark funding for fleets that serve communities disproportionately impacted by emissions, and small businesses should be offered assistance in navigating the programs.

Stakeholders Weigh In

As part of the process for developing the report, DEQ and ODOT held listening sessions with fleet owners, nonprofits and other interested parties.

Commenters spoke highly of California’s Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which offers point-of-purchase incentives that vary with the type and model of truck.

“[Stakeholders] supported adoption of a similar, if not identical, program in Oregon,” the report said.

Commenters also called for consistency among zero-emission truck incentive programs on the West Coast, speculating that better incentives in other states would discourage ZEV purchases in Oregon. On the other hand, Oregon might not be able to sustain incentive programs that are too generous.

Stakeholders suggested calculating ZEV incentives as a percentage of vehicle purchase price or basing them on the cost difference with diesel trucks. Another suggestion was to give incentive recipients more time to buy a ZEV or install infrastructure, due to ongoing supply chain issues.

Another California strategy that was discussed is the state’s requirement for utilities to implement “make ready” systems to streamline infrastructure installation.

“A similar approach in Oregon may cut down installation time — which is currently anywhere from 18 to 24 months — once supply chain issues are resolved,” the report said.

ZEV Truck Collaboration

In 2021, Oregon joined a coalition of 19 jurisdictions — 17 states, the District of Columbia and Quebec — that signed a memorandum of understanding to accelerate the transition to zero-emission medium- and heavy-duty trucks. The group set a goal of making at least 30% of new medium- and heavy-duty truck sales zero-emission by 2030, with 100% ZEV sales by 2050.

In July, the group released an action plan with more than 65 strategies and recommendations aimed at encouraging zero-emission truck adoption. The Oregon agencies incorporated recommendations regarding incentive programs into the new report.

For example, one recommendation is for states to reduce or waive sales tax and registration fees for zero-emission trucks until they cost the same as diesel vehicles.

An analysis by the California Air Resources Board found that model year 2024 ZEV trucks will cost an expected $14,000 to $87,000 more than conventional vehicles, according to the Oregon report.

That cost difference is expected to disappear by 2030.

“While 2030 is not far out, the amount of emission and GHG from diesel vehicles will be costly to the environment and to the health of Oregonians,” the Oregon report concluded. “Incentivizing adoption of ZEV now is imperative to support climate initiative and the livability of Oregon.”

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FERC Accepts SPP Order 845 Compliance Filing, Grants Tx Planning Waiver

FERC late last month accepted a pair of SPP tariff revisions related to generator interconnection procedures and transmission planning.

The commission on Dec. 29 accepted SPP’s Order 845 compliance filing, effective Jan. 1. The 2018 order amended FERC’s pro forma large GI procedures and agreement, intended to improve the interconnection process and ensure it is just and reasonable (ER23-333).

SPP proposed expanding the transfer or use of surplus interconnection service beyond Order 845’s intent by allowing requests for surplus interconnection service (SIS) that require network upgrades in certain situations. Order 845 had required transmission providers to offer SIS to reduce costs for interconnection customers by increasing the use of existing interconnection facilities and network upgrades, rather than requiring new upgrades.

FERC said that by expanding the use of SIS, the RTO’s proposal will accomplish Order 845’s purpose. It found that the proposal would not “undermine” the order’s “open and transparent process for surplus interconnection service.”

“SPP’s proposal includes clear and objective criteria and protects against adverse effects on other interconnection customers in the SPP generator interconnection queue,” the commission said.

It also said the proposal would not result in “inappropriate queue jumping,” as its expansion of SIS is “limited by the requirement that there are no material adverse impacts on the cost or timing of any generator interconnection requests pending at the time the surplus interconnection service request is submitted.”

In a separate order issued the same day, FERC granted SPP’s waiver request for a six-month extension of its deadline to complete its 20-year assessment transmission planning study, from December 2022 to July 2023 (ER23-201).

The RTO said that when it began scoping the long-term assessment with stakeholders, it also began experiencing milestone delays for completing the 2020, 2021 and 2022 Integrated Transmission Planning (ITP) studies as the COVID-19 pandemic began.

Staff and members agreed in 2021 to pause the 20-year assessment and shift staff to the other planning studies to avoid further delays. SPP pointed out that the long-term study only looks for transmission solutions of 300 kV or higher and does not require approval to build transmission projects, as do the other ITP assessments. (See “Tx Planning Mitigation Gets OK,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

FERC said the waiver request met its criteria of being made in good faith, being limited in scope, addressing a concrete problem and not having undesirable consequences.

Co-ops File Complaint vs PSCo

In a complaint filed with FERC on Dec. 30, four Colorado cooperatives charged Public Service Company of Colorado (PSCo) with imprudently planning for and not supplying them with gas for electric generation during the severe February 2021 winter storm.

CORE Electric Cooperative, Grand Valley Rural Power Lines, Holy Cross Electric Association and Yampa Valley Electric Association said the Xcel Energy subsidiary failed to follow its own supply plans and wound up having to buy gas on the spot market at higher prices. They are asking the commission to return to them $6.9 million in fuel charges.

“PSCo’s failure to adhere to its monthly supply plan caused the company to purchase significantly more spot gas than called for in the monthly supply plan, actions a reasonable utility management would not take, constituting evidence of more than a ‘bare allegation of imprudence,’” the co-ops said.

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EPA Proposes Lowering Limit for Small Particle Pollution

EPA wants to cut the annual levels of PM2.5 ― the very small particles of soot produced by fossil fuel combustion ― by as much as 25% from the current standard, which was set in 2012 and kept in place through 2020 by former President Donald Trump.

In a Notice of Proposed Rulemaking announced Friday, EPA said it plans to revise the annual National Ambient Air Quality Standards (NAAQS) from its current level of 12 micrograms per cubic meter (μg/m3) to 9 or 10 μg/m3.

The revised standard is “based on scientific evidence that shows the current standard does not protect public health with an adequate margin of safety, as required by the Clean Air Act (CAA),” the agency said in a fact sheet released with the 569-page NOPR.

PM2.5 is scientific shorthand for particulate matter with a diameter of 2.5 microns or less, which is about 30 times smaller than the diameter of a human hair and invisible to the human eye. “Most particles form in the atmosphere as a result of complex reactions of chemicals such as sulfur dioxide and nitrogen oxides, which are pollutants emitted from power plants, industries and automobiles,” according to information on EPA’s website.

“Long- and short-term exposures to PM2.5 can harm people’s health, leading to heart attacks, asthma attacks and premature death. Large segments of the U.S. population, including children and older adults, people with heart or lung conditions, and minority populations, are at risk of adverse health effects from PM2.5,” EPA said in the fact sheet.

The agency could also be considering revising the standard to as low as 8 μg/m3 or as high as 11 μg/m3, according to the announcement, which asks for comments on each of the proposed figures.

“Our work to deliver clean, breathable air for everyone is a top priority at EPA, and this proposal will help ensure that all communities, especially the most vulnerable among us, are protected from exposure to harmful pollution,” EPA Administrator Michael Regan said.

Doris Browne, former president of the National Medical Association, also stressed the equity and environmental justice impacts of the proposed new standards. “No one should be sickened by the environment they live in, and EPA’s proposal marks the start of changes that will have lasting impacts in communities all over, especially Black and brown communities that often experience increased PM pollution.”

According to the EPA, setting the annual standard at the lower 9 μg/m3 would prevent up to 4,200 premature deaths and 270,000 lost workdays per year. Overall public health benefits could total $43 billion by 2032, the agency said.

While focusing primarily on the annual PM2.5 standard, EPA said it will not propose revisions to the 24-hour standard for PM2.5, now set at 35 μg/m3, noting that “scientific evidence does not clearly call into question the adequacy of the current standard.” However, the agency does ask for comments on lowering the daily standard to 25 μg/m3.

The 24-hour standard for PM10, a somewhat larger form of particulate matter, would also stay unchanged at 150 μg/m3, EPA said.

Publication of the NOPR in the Federal Register will begin a 60-day comment period. EPA will also hold a virtual public hearing on the proposed standards at a date to be announced.

If a region’s air quality fails to meet the new standard, state governments must execute plans to meet the requirement. 

“For PM2.5, such a plan could involve cutting car traffic by improving public transit or instituting carpool lanes. Or, if there are some industrial facilities like coal plants that do not have modern scrubbing technology, the state can compel them to clean up,” said Earthjustice’s Ben Arnoldy in a  blog post. 

A Compromise? 

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The NOPR announcement is part of broader group of actions taken by EPA and the Biden administration, the agency said, pointing to the clean truck rules issued in December as one example. (See EPA Announces Tougher Emission Rules for Heavy-duty Vehicles.) While the proposed revisions would not directly target greenhouse gases, cutting PM2.5 from sources like power plants and cars could also result in lower carbon emissions.

EPA started setting standards for both PM2.5 and PM10 in 1971. According to the agency, the annual and 24-hour standards serve distinct purposes. The lower, annual standard provides protection against health impacts caused by short- or long-term exposure to PM2.5. The higher 24-hour standard is intended to protect against short-term exposures, particularly in areas that could experience high peaks in PM2.5 concentrations.

The EPA Green Book, which tracks compliance with a number of clean air standards, shows Pennsylvania with one county currently not in compliance with existing PM2.5 standards: Allegheny, in the western part of the state. California has 14 counties out of compliance: Fresno, Imperial, Kern, Kings, Los Angeles, Madera, Merced, Orange, Plumas, Riverside, San Bernardino, San Joaquin, Stanislaus and Tulare.

A revised standard of 9 μg/m3 could throw 112 counties, many in California, out of compliance, based on current reported emission levels.

The suggested standard of 9 or 10 μg/m3  appears to be a compromise between two options contained in a March 2022 report from EPA’s Clean Air Scientific Advisory Committee (CASAC).

PM2-5 scale analysis (EPA) Content.jpg

EPA

A majority of committee members recommended the lower 8 μg/m3  standard, while a minority said the higher 11 μg/m3 would be sufficient. Similarly, the CASAC had a split decision on the 24-hour standard, with some supporting no change and others suggesting a cut to 25 to 30 µg/m3.

“There is substantial epidemiologic evidence from both morbidity and mortality studies that the current standard is not adequately protective. This includes three U.S. air pollution studies with analyses restricted to 24-hour concentrations below 25 µg/m3,” CASAC Chair Lianne Sheppard wrote in a letter introducing the report.

The nonprofit Clean Air Task Force cited CASAC in its statement, calling on EPA to go with the lower standards.

“An annual standard of 8 µg/m3 and a 24-hour standard of 25 µg/m3 would require more aggressive action under the Clean Air Act either by states or the federal government to address this problem in polluted areas,” said Hayden Hashimoto, associate attorney for the group. “Therefore, we will continue to urge EPA to set the standards at these levels, as it is critical for public health and the environment that they reflect the current scientific understanding of the threats posed by particulate matter.” 

In response to the announcement, the Edison Electric Institute highlighted the industry’s emissions reductions to date and its intention to take an active role in discussions about any revisions to the standards.

Alex Bond, EEI’s deputy general counsel, said U.S. utilities have cut emissions of sulfur dioxide and nitrogen oxide 94% and 88%, respectively, since 1990, and now produce 40% of their power from “emissions-free sources, including nuclear energy, hydropower, wind and solar energy.”

EEI will work with EPA “to ensure that implementation of the standard is consistent with our industry’s ongoing clean energy transformation,” Bond said.

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Competitive Power Ventures Entering Retail Market

Competitive Power Ventures (CPV) announced Friday that it is launching CPV Retail Energy, a subsidiary to sell power from its “low-emitting” combined cycle plants within the PJM grid to commercial and industrial customers.

“CPV is excited to launch this new platform, which will enable the company to share the benefits of its renewable and world-class low-carbon fleet directly with customers,” Qadir Khan, president of CPV Retail Energy, said in an announcement of the launch. “The retail team has decades of experience in building successful retail platforms, and we look forward to developing this new customer-focused platform.”

Matt Litchfield, director of external and regulatory affairs, told RTO Insider that CPV has a unique generation fleet in that most of its traditional thermal assets have come online since 2016, meaning its units have some of the most efficient and low-emission technology. The company also has more than 4,000 MW of renewables in its development queue across the nation, which brings its total generation to 7,000 MW in development, construction and operation.

“There’s other companies out there that offer renewable options, which we will as well, but there’s not a lot of other companies out there offering a low-carbon product as well,” Litchfield said of the company’s reasons for entering the retail market.

The company is also embarking on a $3 billion development of an 1,800-MW combined cycle facility equipped with carbon capture technology in West Virginia, in part using tax credits under the federal Inflation Reduction Act. Litchfield said the project is indicative of the type of low- and zero-carbon emitting generation options the company will offer to consumers.

With the majority of the company’s assets based within the PJM footprint, CPV Retail Energy will begin by focusing its operations in Delaware, Illinois, Maryland, New Jersey, Ohio, Pennsylvania and D.C. The company has plans to expand into New York and New England.

“With plans and products from CPV Retail Energy, customers will have access to reliable electricity sourced from a company that is not only committed to the environmentally responsible production of electricity, but that also places a strong emphasis on being a good corporate citizen and operating with integrity,” Khan said in the announcement. “We can’t wait to get started growing CPV Retail Energy into a premier ‘Greentailer’ in the retail electric power industry and offer customized pricing plans including 100% renewable options.”

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Regulators File Emergency Motion in Ongoing Grand Gulf Battle

The convoluted and long-running clash over refunds due from years of alleged mismanagement and performance issues at Entergy’s Grand Gulf Nuclear Station took another twist last week when regulators accused the utility of publicizing a false narrative.

The Arkansas and Louisiana commissions and New Orleans’ city council filed an emergency motion Jan. 3 after an Entergy press release one week before.

The utility claimed FERC’s recent decision on Grand Gulf tax maneuvers meant it owed no additional refunds to ratepayers. The regulators, who were expecting hundreds of millions in refunds, asked FERC to correct the press release immediately (EL18-152, et al.).

The regulators and New Orleans have complained for years about mismanagement and substandard operations at the nuclear plant and sought refunds and rate reform on more than $1 billion in costs passed on to Entergy customers in their states and Mississippi. They said that despite expensive upgrades, the plant has been plagued by frequent outages at the expense of customers. (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)

The uproar centers on Entergy subsidiary System Energy Resources Inc. (SERI), majority owner and wholesaler of Grand Gulf’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans subsidiaries. In a pair of December orders concerning the nuclear plant, FERC ruled that SERI excluded decommissioning liability accumulated deferred income tax (ADIT) balances in rate bases from 2004 into the present, violating FERC’s tax normalization requirements (ER18-1182).

The commission also decided that SERI overcharged on the $17 million in Grand Gulf annual lease payments it collected from 2015 through 2022, ordering $149 million in ratepayer refunds (EL18-152).

FERC said the refund amount “appropriately captures the revenue requirement impact resulting from the exclusion of all ADIT amounts resulting from SERI’s decommissioning uncertain tax positions during the entire 2004 to present period of noncompliance.”

Entergy CEO Drew Marsh said in the company’s press release that the utility was “pleased that FERC’s remedy results in no additional refunds due to customers beyond those already provided in 2021 on the uncertain tax positions taken by SERI.”

Entergy said FERC’s refund ruling means that the issue will be completely addressed through its previously enacted $69 million rate base credit to customers for Grand Gulf’s expected lifetime and its one-time credit of $25 million in 2021 to remedy 2015’s decommissioning tax deduction.

The company said the commission’s decision stipulated that the refunds must not “re-establish” SERI’s ADIT balances for tax positions that were denied by the IRS and therefore didn’t benefit the company. The utility explained that except for a $100 million partial acceptance of its 2015 tax position, the IRS didn’t permit any of SERI’s other uncertain decommissioning tax positions.

“Under the remedy specified by FERC, for uncertain tax positions that the IRS fully disallowed, and for which SERI received no tax benefits, no refunds are due. We therefore calculate the remaining refund for the uncertain tax positions issue to be $0,” Entergy said.

“The position Entergy asserts in its press release is a blatant and perhaps intentional misrepresentation of the commission’s orders,” the state and city regulators told FERC. “Unless corrected, it may cause substantial damage to Entergy investors and at the least will mislead those investors and the consuming public. A clarifying statement from the commission can diminish these consequences.”

Entergy released a statement on Thursday addressing regulators’ emergency motion. It said it was “following FERC’s regulatory process” and plans to file compliance “detailing the refunds that we believe are required by the FERC order.”

However, the utility doubled down and said SERI owed no additional refunds stemming from its ADIT tax positions.

“As we’ve consistently said, SERI’s tax strategy was conducted in the best interest of our customers and ultimately saved millions of dollars in operating expenses. Those cost savings have already been passed on to our customers, and we believe we have already paid the refunds due under the remedy FERC outlined on the uncertain tax positions taken by SERI,” the company said.

Entergy added that a global settlement of all SERI dockets is in the “best interest of all parties.”

The state regulators and New Orleans also allege Entergy recovered the costs of lobbying, image advertising and private airplane use in rates through the plant’s sales agreement.

Entergy has offered its regulators nearly $600 million to resolve the Grand Gulf complaints, with $235 million to the Mississippi Public Service Commission, $142 million to the Arkansas Public Service Commission, $116 million to the New Orleans City Council, and $95 million to the Louisiana Public Service Commission. Only the Mississippi PSC has taken Entergy up on its offer. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

Entergy also said last week that it will seek a rehearing of FERC’s decision that SERI owes nearly $150 million in refunds because it improperly billed the costs of Grand Gulf’s sale leaseback renewals in its formula rate. The utility said the sale leaseback renewal “was entered into to lower costs to customers, which is a benefit that FERC previously recognized.”