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November 18, 2024

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FERC Dismisses Gas Policy Update Rehearing Requests

FERC on Tuesday dismissed 14 requests for rehearing of its revised policy statement on natural gas infrastructure and its interim policy on accounting for greenhouse gas emissions, citing that it had reverted the policies to drafts after the requests had been filed (PL18-1-002, PL21-3-002).

“The draft policy statements do not constitute any final commission determination,” FERC said. “Because commission action is not final and because the rehearing parties are not aggrieved by a statement of policy, rehearing does not lie and dismissal is appropriate.”

The decision was unanimous among the five commissioners, but Commissioner James Danly issued a concurring statement noting that making the policy statements drafts does nothing to alleviate the uncertainty expressed by the petitioners, nor does it address any of his concerns about their legality.

Though Danly agreed that the requests were null now that the statements were drafts, “the ‘fog of indecision’ still lingers over the development of natural gas infrastructure,” he wrote. “What will happen [when the commission issues final proposals] is anyone’s guess. I fear that the philosophy animating the issuance of the policy statements in the first place will ultimately result in similar issuances in the future.”

Both Danly and fellow Republican Commissioner Mark Christie were strongly critical of the two updates, issued in February at FERC’s monthly open meeting as final policies that would begin to apply immediately, including to projects already filed with the commission. FERC walked them back a month later at its next meeting, with the majority citing feedback it had received that they were confusing. (See FERC Backtracks on Gas Policy Updates.)

The rehearing requests were filed by several gas pipeline groups and trade associations, as well as several states including Texas and Louisiana. Among their complaints was the retroactive application of the policies, but FERC said that when it issues its final statements, they would not apply to pending projects.

FERC noted in its order that it would include the petitioners’ requests as comments in the dockets, for which it is collecting public input by April 25. While Danly said he was gladdened by this, he expressed skepticism that the majority would address the petitioners’ concerns.

“And I have a good basis for that concern,” he wrote. “The interim GHG policy statement sidestepped many of the exact same arguments parties have made on rehearing, including the argument that the commission cannot do indirectly what it is prohibited from doing directly and that courts have found that Congress has vested the U.S. Environmental Protection Agency, not FERC, with the authority to regulate GHG emissions. Perhaps if the commission had thoughtfully (or even cursorily) considered these arguments in the first instance, it would not be in the position that it is now.”

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NJ Seeks Efficiency, Savings in OSW Transmission Process

The cost to New Jersey ratepayers of building transmission infrastructure tying the state’s offshore wind projects to the grid could be cut, and the risk of cost overruns diminished, under some of the 80 proposed projects submitted to the state Board of Public Utilities (BPU), stakeholders at a hearing into the issue argued Tuesday.

Such a strategy, if approved by the BPU, would provide a transmission system for about half of the 7.5 GW of offshore wind planned by the state, said developers and stakeholders during the three-and-a-half hour hearing on the BPU’s planning process with PJM under FERC’s State Agreement Approach (SAA). That would be a stark departure from the plans in place for the development of transmission infrastructure for the first half of the planned offshore wind capacity.

Each of the three offshore wind projects awarded by the BPU so far — Ocean Wind 1, Ocean Wind 2 and Atlantic Shores, which collectively would generate 3.758 GW of power — will design and develop their own transmission infrastructure. But the SAA process would allow one or more developers focused solely on transmission issues to design the infrastructure to connect projects awarded in the future to the grid.

Having a single project serve several projects could reap efficiencies of scale, create a more reliable system and reduce the cost to ratepayers through competitive bidding coupled with cost caps to prevent the amount paid by ratepayers from escalating beyond the contracted amount, developers said.

Becky Walding, executive director of development for NextEra Energy Transmission MidAtlantic (NYSE:NEE), said the company had calculated that the process could save “customers billions of dollars” if it results in transmission infrastructure serving several wind farms, rather than each providing their own cable system.

“There is the possibility for substantial cost savings,” added Theodore Paradise, executive vice president of transmission strategy for Anbaric Development Partners. “If you’re avoiding more cables, more trenching, more shore landings, more upgrades [and] more substation expansions because you’re making the most out of the breaker positions that you have in a substation, those are the sorts of things that can really save some money.”

But Larry Gasteiger, executive director of trade association WIRES, urged the BPU to proceed with caution. Cost caps can be weakened by “exclusions” that allow items to be charged outside the cap, and focusing on a project’s cost can sometimes be detrimental to ratepayers, he said.

“The real question here is: Do you really want the cheapest upfront design for your transmission solutions?” he said. “It raises a number of other related questions such as, what is the risk tolerance for what may be a cheaper, but less proven or unproven design over perhaps something that may wind up being more costly in terms of the design, but uses a more well established or more proven track record as the basis for that design?”

Risk vs. Cost Trade-off

The issue of how best to structure the development of future transmission infrastructure emerged as one of the most contentious topics at the BPU’s fourth and final hearing into the SAA proposals, which focused on “ratepayer protections and cost controls.” Under the SAA process, the BPU, working with PJM, solicited proposals for developing links between the grid and the offshore wind projects.

The last meeting in the series included a presentation by Michelle Manary, acting deputy assistant secretary of the Energy Resilience Division at the U.S. Department of Energy, on federal funding for offshore wind, and a panel discussion afterward that included three transmission project developers; Gasteiger; the director of the New Jersey Division of Rate Counsel; and a representative of PSEG, which owns 25% of one of the state’s offshore wind projects and submitted transmission proposals with Ørsted.

Earlier hearings presented the 80 proposals submitted by 13 developers and focused on permitting and environmental issues and grid integration issues.

The BPU, working with The Brattle Group expects to decide by October whether to adopt any of the proposals. Alternatively, it could reject them all and continue as it has so far. (See Fierce Competition in Plans to Upgrade NJ Grid.) The board has held two offshore wind solicitations and awarded three projects, each of which included the design of a transmission system to bring the power to the grid. Three more solicitations are planned, the first to take place in January 2023. (See NJ Awards Two Offshore Wind Projects.)

Rate Counsel Director Brian O. Lipman said the BPU, in assessing the proposal, needs to focus on key benefits to the state, and not get distracted by broader issues.

“For this proceeding, the real issue is not about addressing the pre-eminent challenge of climate change, but rather how will New Jersey select resources that are economically sustainable and environmentally sustainable; in this case, transmission lines,” he said. “The only issue is whether any of the proposed offshore wind transmission projects meet these goals. And if so, which are the best fit?”

The rate counsel encouraged the state only to support projects that would benefit New Jersey and not “promote regional solutions to OSW development along the Atlantic Seaboard.” New Jersey ratepayers should “not be placed in the position of subsidizing OSW development benefits for other states and regions,” he said. State officials in the past have expressed a more expansive view, saying they want New Jersey to be an offshore wind manufacturing and supply chain hub that can serve other states. (See NJ Plans ‘Flagship’ R&D Innovation Center for Wind.)

Lipman said the BPU should pick projects that fit the state’s needs and not “facilitate overdevelopment” that could “place New Jersey ratepayers in the position of having to bear the risk of future project OSW transmission benefits that never materialize.” He added that the BPU should look for projects that “offer to mitigate or assume some risks,” such as development, financial, market and regulatory risks, and require the developer to take on some of them.

“It is likely that any offer to mitigate these risks will not come free,” he said. “Thus, balancing risks and costs to determine the most advantageous proposal or proposals will involve some tradeoffs.”

Structuring the Deal

The projects would be funded by a tariff authorized by FERC that would amortize the cost of the projects over their life. PJM would then allocate the costs to the utilities serving the state, who would in turn charge the cost as a transmission fee in ratepayer bills.

How that will impact ratepayers is not clear. Lathrop Craig, vice president of development for Public Service Enterprise Group (NYSE:PEG), said the company has yet to calculate the cost of transmission, which will in any case vary depending on which project or projects the BPU chooses. But PSEG calculated that the entire cost of each of the three offshore wind projects approved so far would for the average residential account be “in the low single-digit dollars per month,” so the cost of just transmission would be much less, he said.

Speakers differed, however, on the best way to keep those costs down and curb the risk to ratepayers of rising costs.

Clint Plummer — CEO of Rise Light & Power, a New York-based wind project development company that is a subsidiary of LS Power — argued that giving the developer responsibility for all the offshore transmission infrastructure, as well as developing the project, would secure efficiencies by “putting the developers in control of every piece of the project.” That strategy has worked successfully in the past, he said.

“You give the developers not only the ability to manage their projects to deliver a lower cost to ratepayers, [but] you put more of the risk on the developers” and keep it off the ratepayers, Plummer said. Rise submitted a proposal to provide the onshore interconnection by developing a former fossil fuel plant, the Werner Generating Station in South Amboy, on a bay that fronts the New York Bight. He also argued that “it’s very difficult to optimize a wind farm if you don’t control the means by which you’re delivering your final product to market.”

But other developers argued that a separate competitive selection process to pick the transmission infrastructure would drive down costs.

“The competitive pressure of the State Agreement Approach will create tremendous value for New Jersey ratepayers in terms of cost savings and risk mitigation,” said Lawrence Willick, executive vice president of transmission regulatory for LS Power, which submitted proposals to build both onshore and offshore transmission infrastructure.

The process also will protect ratepayers by including cost caps “to actually contain the cost of transmission” development and prevent them from getting burdened with cost overruns from issues such as unforeseen schedule delays, said Anbaric’s Paradise.

AC vs. DC

A key element of the transmission system’s cost structure, however, comes from the technology used, said developers, who offered differing visions at the forum. The issue centers on whether the project uses high-voltage alternating current (HVAC) or HVDC, which is more efficient for transferring power over long distances because it incurs less power loss.

Rise CEO Plummer said HVDC systems come in “large blocks” of 1,100 to 1,500 MW, and that unless the project is a multiple of those sizes, its use would result in the creation of wasted capacity. HVAC, meanwhile, comes in blocks of 400 MW, which is far more flexible and suitable for most of New Jersey’s offshore wind areas, he said.

“HVDC makes a lot of sense for sites that are really far from shore,” he said. But more than 70% of the offshore wind area still to be leased in New Jersey “can connect to the shore with HVAC technology,” he said. “That has real advantages because HVAC is not only a more proven technology in the offshore environment, but it also is a lot cheaper.”

Willick agreed that the “distances really aren’t that long to justify the higher cost of the DC terminals,” and that HVAC systems have the benefit of lasting longer than HVDC systems, which would likely need to be replace during the project’s life.

“So really, if an AC approach does work, and is feasible, then that’s the best approach,” Willick said. “It integrates with the existing system and avoids the high cost and losses of the DC equipment.”

Paradise argued that HVDC is the best option if the state is planning for large capacity. Such a system would avoid creating “the spaghetti of all of those radial lines” running from each project to the shore and be cost effective, he said.

Anbaric submitted proposals for both transmission corridors and an offshore network. It estimated that New Jersey’s entire planned wind farm capacity of 7,500 MW could be handled by five HVDC cables, whereas it would require 19 HVAC cables, Paradise said.

“If you’re going to go big in terms of significant amounts of megawatts and building out robust transmission systems,” HVDC is preferred, he said. “So, if New Jersey is saying 7,500 [MW] is a down payment, but we want to go to 15,000 [MW], then designing a system is really important.”

NextEra’s Walding said the company designed the projects it planned to submit in two scenarios, AC and DC, and found the latter to be cheaper.

“We actually didn’t even propose the AC because it was significantly more, to the tune of 50% more expensive,” she said. “It ended up with more platforms in the ocean on that design. And, so from a cost perspective, we didn’t feel like it was the right thing.”

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New Draft of Advanced Clean Cars II Would Speed ZEV Sales

The California Air Resources Board has released a new draft of its proposed Advanced Clean Cars II regulation featuring a faster ramp up to 100% zero-emission vehicle (ZEV) sales in 2035 than an earlier draft of the rule.

The new version of the regulation would require 35% of new car sales in the state to be ZEVs in 2026. ZEV sales percentages would increase in each subsequent year, climbing to 43% in 2027 and 51% in 2028, before reaching 100% in 2035 and beyond.

A December 2021 draft of the regulation included a 26% ZEV sales requirement in 2026, followed by 34% in 2027 and 43% in 2028. The previous draft and the new version list the same ZEV sales percentages from 2031 through 2035, starting with 76% in 2031.

CARB released the new draft regulation on Tuesday and scheduled a public hearing on the proposed rules for June 9. Written comments may be submitted from April 15 through May 31, or during the public hearing.

‘Significant Milestone’

The proposed Advanced Clean Cars II regulation is a follow-up to CARB’s current Advanced Clean Cars rule.

The regulation consists of two programs. The ZEV program requires an increasing percentage of light-duty car and truck sales in the state to be zero-emission each year. The second component is the low-emission vehicle program (LEV), which sets standards for tailpipe emissions of greenhouse gases and smog-forming pollutants.

The current Advanced Clean Cars regulation sets a ZEV sales requirement of 22% in 2025. This year, the requirement is 14.5% ZEV sales.

Don Anair with the Union of Concerned Scientists called the new draft regulation a significant milestone for California as it’s the first regulatory proposal to bring the state to 100% ZEV sales by 2035. Anair is the research and deputy director for the Clean Transportation Program at UCS.

UCS had criticized the slower ramp up toward 100% ZEV sales requirement in last year’s proposal, saying that ZEV sales trends and automaker announcements showed that a more stringent regulation was feasible. And a faster ramp-up is needed to combat climate change, the group said.

Anair told NetZero Insider Wednesday that the more stringent ZEV requirements in the new proposal are “a significant improvement.”

In addition, Anair said that assurances in the proposed regulation — including battery labeling and warranty requirements — would bring more confidence to the used ZEV market.

EJ Credits Proposed

The regulation’s proposed environmental justice credits are another positive, Anair said, although he noted the voluntary credits don’t guarantee that more ZEVs will be provided to disadvantaged communities.

The environmental justice credits, which were first proposed last year, offer additional ZEV credits to car manufacturers that provide a new ZEV at a discount to a qualifying community-based clean mobility program. The discount must be 25% or more of the manufacturer’s suggested retail price. The credits would be available for model years 2026 through 2031.

CARB’s new proposal also retains a plan discussed last year to allow the transfer of credits from out-of-state ZEV sales.

If a car manufacturer earns more credits than required in a state that has adopted California’s ZEV program, those excess credits could be transferred to another state to make up a credit shortfall. The transfer would be limited to the number of credits needed to satisfy the deficit, and the transfers would only be allowed for model years 2026 through 2030.

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Electricity Markets Benefit from Competition, Former Regulators Say

The decades-long move to competitive wholesale and retail electric markets in the U.S. continues to stir controversy, but the numerous benefits can sway attitudes, several former regulators said.

Pat Wood (R Street) Content.jpgPat Wood, Hunt Energy Network | R Street

The pace of innovation sped up when monopoly providers were invited to sit down and let others participate, former FERC Chair Pat Wood, now CEO of Hunt Energy Network, said during an R Street Institute webinar Tuesday. Wood who led FERC from 2001 to 2005, previously headed up the Public Utility Commission of Texas.

The rules that clarify how technologies play in a market, interconnect and pay for their costs can have a dramatic impact, he said.

“We got in the early days in Texas a humongous slug of brand new gas-fired generation taking advantage of those clear rules and big welcome mats, and then right on their tails were wind and now solar coming here as well as in SPP and MISO,” Wood said. “It’s one thing to have a resource, but it’s another to actually have the investment to capture it and convert it into electricity.”

Unbundling more than a century of energy market structure, as FERC did with natural gas, takes some effort, thoughtfulness and authority, which the commission “had plenty of on the gas side and has considerably less on the power side, but a very dominant role nonetheless,” Wood said.

New Technologies

New technologies from battery storage to aggregated distributed resources have the capacity to provide further benefits to consumers, but the existing framework within the RTOs/ISOs put up artificial barriers that prevented these resources from being compensated for all their attributes, said former FERC Chair Neil Chatterjee, a senior advisor at Hogan Lovells, who served on the commission from 2017 to 2021.

“We had two pretty significant FERC orders during my tenure: FERC Order 841 regarding storage and FERC Order 2222 regarding aggregated DERs. … Some of the most significant actions the commission could have taken to address how to innovate within the market,” Chatterjee said. “We were highly intentional on FERC Order 2222 for some of this innovation to have the opportunity to thrive.”

Neil Chatterjee (R Street) Content.jpgNeil Chatterjee, Hogan Lovells | R Street

“Conservatives love it when new technologies come in and upend existing markets, [such as] when Uber comes in and breaks up the taxi unions. But for some odd reason when it comes to electricity, it’s ‘No, no. This is how we’ve been doing it for 125 years. We have to continue to do it in this manner,’” he said.

Chatterjee called that “an outmoded way of thinking” and expressed optimism that more conservatives — and more conservative states — will “embrace the benefits of free market competition.”

“The southeast did at least take a step in the right direction with [the Southeast Energy Exchange Market] to move towards a market,” he said. “I wish we’d gone farther in the Southeast, but I also understand the reluctance to engage in markets there.” (See Southeast Utilities Defend SEEM Proposal.)

There is interest across the country in looking at market expansion, with $19 million in President Biden’s budget to study RTO participation and its benefits, he said.

“I do want to clarify, ironically, that it’s not necessarily a red state or blue state thing,” Chatterjee said. “FERC could be more muscular in this area, but one of the reasons the commission has not [been] … is that most of the senators on the Senate Energy and Natural Resources Committee, which is the committee that FERC nominees have to go through for confirmation, are now from non-RTO states. That in strange ways had a limiting effect of FERC acting in this regard, because it’s not just Republican senators, there’s Democratic senators who also have some reticence about this.”

Between Extremes

People tend to resist change, and lawmakers and regulators are especially sensitive to changes to electricity markets, Wood said.

Part of the problem is that most of the public, including lawmakers and regulators, think there are two options, either the Texas model of completely deregulated open retail markets or the traditional Florida model with vertically integrated monopolies, said Landon Stevens, former policy advisor at the Arizona Corporation Commission and now director of policy and advocacy at the Conservative Energy Network.

Landon Stevens (R Street) Content.jpgLandon Stevens, Conservative Energy Network | R Street

“There’s actually a continuum of competition, with policies, regulations and different innovations you can add between those two points,” Stevens said

Some Republicans can convince themselves that “joining the crony capitalism world … is the chamber of commerce way to do things,” Wood said.

Monopolies are antithetical to governance of a free people, but regulators implemented them at the time because they viewed electric power supply as a natural monopoly, he said.

“Regulators shouldn’t be shellacked when they blow the BS meter and say we’re going to change this. But change needs to be gradual because people have contracts based on the old way of doing things,” Wood said. “When people are jumping on the regulators for changing how solar tariffs work or net metering … I don’t like what they’re doing either, but it’s not unfair. They are doing their job; they’re trying to allocate costs based on cost occurrence.”

It is incumbent on states that care about creating customer benefits to perform rate design more correctly, but opponents of that are adept at shaping outcomes, he said

“The status quo is hard as hell to bust,” Wood said.

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Maryland Bills Could Boost Community Solar, Local Resilience, Clean Trucks

Community solar projects in Maryland could get bigger and get a break in property taxes, thanks to two bills approved by the state’s General Assembly during the final days of its 2022 session, which ended on Monday.

House Bill 440 would raise the maximum size of community solar projects eligible for virtual net metering from 2 MW to 5 MW. Under House Bill 76, community solar projects of up to 2 MW will be eligible for a property tax exemption, provided that half of the electricity from the project goes to low- or moderate-income customers and costs them at least 20% less than the energy charges of their local utility.

A third bill, SB 860, also sets up a property tax exemption for community solar projects used in “agrivoltaics,” which is defined as “the simultaneous use of land for both solar power generation and agriculture.” The bill would also require school districts planning new schools between 2024 and 2033 to consider adding solar to the projects and to provide a report to the state if they decide against it.

These three bills were among the more than 20 energy- and climate-related pieces of legislation that the General Assembly passed before its final adjournment on Monday, sending them to Gov. Larry Hogan (R), according to the Maryland Clean Energy Center (MCEC).

Two additional climate bills, SB 528 (the Climate Solutions Now Act) and HB 740, became law on Friday without Hogan’s signature. (See Md. Climate Bills Become Law Without Hogan’s Signature.)

In a Tuesday email, MCEC provided a rundown of the 90-day session, noting that it had tracked 79 bills, a figure that included 42 cross-files: similar bills filed separately in the House of Delegates and the Senate.

For example, SB 61, and its cross-file HB 10, both would require the Maryland Transit Administration to provide its operations and maintenance workforce with the training needed to safely operate and maintain the electric buses it will be adding to its fleet. According to both bills, beginning in 2023, any new buses the MTA buys for the state fleet will have to be zero-emission vehicles.

Both bills passed in the final six days of the legislative session, which means the General Assembly now has 20 days to get the bills to the governor’s desk. Hogan will then have 30 days, not including Sundays, to sign or veto them, or allow them to become law without his signature.

Hogan signed 79 bills into law on Tuesday, but none of the bills tracked by the MCEC were included.

Administrative Fixes

For clean energy advocates, SB 528 was the most closely watched bill this session. Sponsored by Sen. Paul Pinsky (D), the bill survived substantial amendments in the House but maintained its topline provision: raising Maryland’s target for reducing greenhouse gas emissions from 40% to 60% over 2006 levels by 2031 and setting the state on a path to net-zero emissions by 2045.

HB 740 requires the state’s retirement system to incorporate climate risk into its evaluations of investments.

Some of the other bills passed were largely administrative. For example, SB 257 changes the date on which the Public Service Commission must submit a yearly report on solar net metering to the General Assembly from Sept. 1 to Nov. 1. It also rolls back a requirement for the PSC to report to the legislature on its efforts to educate the public on the state’s competitive retail power market.

Similarly, SB 215 would extend the sunset date for the state’s tax credit for residential and commercial energy storage installations from Dec. 31, 2022, to Dec. 31, 2024. Following the sunset of the tax credit, the bill would establish an energy storage grant fund to reimburse residential or commercial owners up to 30% of the cost of their storage systems, with a cap of $5,000 for residential systems and $150,000 for commercial systems.

SB 179 would allow state agencies to enter into energy-efficiency performance contracts for terms of 30 years, doubling the current 15-year maximum length. These contracts ensure a specific level of savings from the energy-efficiency measures they provide, or the vendor must pay the difference to the state.

New Programs and Initiatives

Other bills would create new programs and initiatives, such as the Resiliency Hub Grant Program in SB 256. The program would provide funding for communities to develop “resiliency hubs”: microgrids powered by solar and battery storage that would provide electricity for critical services, such as emergency heating and cooling and storing medicines that need refrigeration, during power outages lasting more than four hours. The program is intended to serve low- and moderate-income communities.

SB 526 would require the PSC to determine what level of offshore wind renewable energy credits (ORECs) electric distribution companies will need to acquire to comply with the state’s renewable portfolio standard. The bill would also allows distribution companies to recover their OREC costs from customers.

And HB 1391, the Clean Cars Act of 2022, would set up a fund to help offset the cost to local governments of purchasing medium- or heavy-duty ZEVs. For the years 2024 to 2027, the bill would require the state to allocate $1 million/year for grants for medium-duty vehicles and $750,000/year for heavy-duty vehicles.

A Youngkin Veto and Suggested Amendment

Virginia Gov. Glenn Youngkin on Monday vetoed 25 bills, including SB 347, which would have required Dominion Energy (NYSE:D), the state’s largest investor-owned utility, to ensure its energy-efficiency and demand response programs were benefiting low-income households, the elderly and disabled, and military veterans. The bill also called on the utility to cut the energy use of these customers by 1% annually.

Youngkin’s reason for the veto, as delivered to the General Assembly, was that bill stated that such program requirements were in the public interest, which would “unnecessarily restrict the constitutional authority” of the State Corporation Commission.

“Although this legislation has the commendable goal of promoting energy efficiency, the requirements included in this legislation could, through an arbitrary declaration of the public interest, increase energy costs on Virginians,” Youngkin said.

Another bill, HB 450, was among the 100 that Youngkin sent back to the legislature with recommended amendments. The original bill would have made it illegal for drivers of cars with internal combustion engines to park in spaces reserved for charging electric vehicles, with fines of up to $50 for infractions. Youngkin suggested knocking down the penalty to $25.

Similar bills in Maryland, SB 146 and HB 157, do not specify an amount for the fines for such infractions. Both passed and are on their way to Hogan.

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MISO Considers Adding Smaller Congestion Relief Projects

MISO said Tuesday that it’s contemplating adding a class of smaller, congestion-relieving projects under its annual transmission planning.

Engineering adviser Ben Stearney told stakeholders during a Planning Subcommittee meeting that staff was inspired by its Targeted Market Efficiency Projects (TMEPs) process with PJM. MISO studies TMEPs for interregional purposes only, not under its own regional planning.

Stearney said the RTO may introduce additional TMEP-style planning to its annual Transmission Expansion Plan (MTEP) to alleviate the footprint’s increased congestion. He said “a TMEP-like process in a regional context” with a traditional production cost analysis could produce smaller transmission projects that clear congestion near existing generation resources.

Under MISO’s TMEPs process with PJM, projects must cost less than $20 million, completely cover installed capital cost within four years of service and be in service by the third summer peak from its approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

Stearney said staff are conducting an “exploratory investigation” and could introduce a TMEP-like component in time for MTEP 23. MISO will begin building the MTEP 23 economic models near the end of the year.

WPPI Energy engineer Steve Leovy said he appreciated the evaluation because congestion costs have skyrocketed in the last two years and because MISO hasn’t conducted a market congestion planning study as part of MTEP since 2019. Leovy said the grid operator lacks “ongoing economic planning occurring in the near term.” He pointed out that MISO’s long-range transmission planning looks out at least 10 years, leaving immediate congestion fixes unaddressed.

The RTO’s members late last year questioned whether MISO’s planning is sufficiently addressing mounting transmission congestion.

Leovy has said generators in the footprint’s northwestern system with firm transmission service are feeling congestion’s squeeze and has said MISO’s economic modeling may not be capturing all congestion-relief opportunities.

The RTO might be assigning network upgrades that don’t consider all impacts of new generation projects given the raft on new projects in the Northwest, Leovy contends.

Last month, MISO’s Independent Market Monitor warned that MISO’s day-ahead and real-time congestion increased this winter by 142% and 118 %, respectively, compared to last winter. The Monitor said about half of the real-time congestion could be attributed to wind generation. (See MISO Says System Volatility Here to Stay.)

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NJ Tries to Balance Solar Growth vs. Farmland Protection

Drafted to help achieve an ambitious goal of nearly quadrupling New Jersey’s solar output over the next decade, new rules proposed by the state Board of Public Utilities (BPU) to govern what land can be used for projects received a moderate reception last week, with little outright opposition but a stream of queries and suggested improvements.

More than a dozen speakers — among them solar developers, environmentalists and farming advocates — raised a host of thorny issues, among them how the rules would work in practice, what protections for soil are in place and how flexible the guidelines would be when enforced. Key among the issues raised by developers were concerns that the cost of compliance would be so great that projects would become unviable.

“I do think that job No. 1 should be to make sure that we can accomplish these purposes at the lowest possible cost,” said Fred DeSanti, executive director of the New Jersey Solar Energy Coalition.

Matthew Tripoli, director of project development at CS Energy, said the company supported statewide standards that would apply to all projects.

“It’s a great idea to have having the rules be extremely clear, as it looks like [that’s what] the attempt is here with these guidelines,” he said. “We’re just a little concerned that the guidelines as proposed don’t really seem to provide much flexibility and seem to value [agriculture] impacts over and above all others.”

Ethan Winter — Northeast solar specialist for the American Farmland Trust, which works to protect farmland and promote environmentally sound farming practices — said the BPU should place greater scrutiny on what soil would be affected by proposed projects and how to reduce the impact.

“We would encourage New Jersey to set a high standard in terms of minimizing and avoiding soil disturbance in the first place,” he said.

The release of the guidelines follows growing concerns in New Jersey, as in other states nationwide, over the impact of rising demand for space on which to site solar projects on farmland. Aggressive demand for land, and related high-priced lease and purchase offers from developers, has forced farmers to decide whether to accept the income from solar opportunities or reject it to protect their farms and way of life. (See NJ Solar Push Squeezes Farms.)

A similar dynamic has played out in Ohio, where solar supporters see a 350-MW project on 1,880 acres of prime farmland bringing much needed revenue for schools. In San Diego, local officials see solar developments as key to cutting carbon emissions and eye farmland as the place to put them.

In New Jersey, there is an additional dynamic: The pressure to develop farmland has been elevated by an explosion in the demand for warehouse space from e-commerce and logistics companies that serve the Port of New York and New Jersey and the massive New York-area population.

Evaluating Solar Sites

The hearing was the second into the siting proposals, which were drafted as part of the state’s new Competitive Solar Incentive (CSI) program.

The program governs utility-scale projects and net-metered commercial installations larger than 5 MW. It is part of the state’s Successor Solar Incentive (SuSi), which the BPU approved in July as part of a reshaping of the state incentive programs designed to reduce the cost of projects while stimulating the development of certain types.

New Jersey Gov. Phil Murphy wants the state to reach 100% clean energy by 2050, with solar a key part of the equation. The state’s official Energy Master Plan calls for deploying increasing amounts of solar: 5.2 GW by 2025; 12.2 GW by 2030; and 17.2 GW by 2035. Yet the state’s new installation capacity in recent years has been well below what would be needed to reach those goals.

The location guidelines under the CSI program divide potential solar sites into four categories, each of which treats the projects differently. One category covers land on which any development is prohibited, which includes preserved farmland and areas that contain prime agricultural soil. A second category — such as wetlands or forest land protected by the state — allows construction only if the BPU approves a waiver. A third category allows the siting of a solar project subject to a cap that limits how much of that land can be developed for solar capacity statewide. And the fourth category is land for which there are no restrictions on what solar developments can be undertaken.

The rules also set out guidelines designed to mitigate the impact on the land of an approved project as it advances to completion. The rules include a requirement that the developer hire an environmental monitor, take stormwater management measures and implement soil stabilization measures.

The aim of the rules is to “minimize as much practical and potential environmental impacts, and include consideration of existing and prior uses of the property, any conservation or agricultural designations associated with the property and the amount of soil disturbance,” Steven Bruder, planning manager for the State Agricultural Development Committee, told the hearing. “The soil protection guidelines are intended to apply whenever the intention is to return lands to agricultural use [at] the end of the life of the solar installation project.”

That scrutiny will include a “six-year-monitoring period” that will include an evaluation of the site every other year, said Frank Minch, director of the Department of Agriculture’s Division of Agriculture and Natural Resources.

Protecting Soil

The close evaluation of the site made sense to Amy Hansen, policy manager at the New Jersey Conservation Foundation, who said she also owns and operates and organic fruit and vegetable farm. She urged the state to ensure that the project inspector has a good knowledge of “soil health.”

“I think it’s important to not be under the impression that topsoil will ever return to its original condition once it’s been removed and moved,” she said. “Removal of topsoil will negatively impact the soil structure and chemistry, as soils form over thousands of years. It’s a delicate balance. So, I think protecting soils, especially prime and soils of statewide importance, really needs to be a strong requirement.”

That kind of close attention to the soil, however, raises concerns for Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, who said that parts of the industry already embrace some of the BPU’s proposals, such as hiring an environmental monitor. He said a “workable siting process is imperative” if the state is to create enough new capacity to meet its goal of 1,500 MW of large-scale solar facilities by 2026, and suggested that some of the guidelines go too far.

For example, a BPU requirement that the developer conduct a soil compaction test every 250 feet before and after construction could be “unduly burdensome and impractical for larger facilities,” he said. And a requirement that land be seeded and mulched within “seven days of disturbance” is impractical; the time period should be extended to 90 days, he said.

“We really do think this is moving in an OK direction,” he said. “But we do think we need to further balance the need for permitting more solar projects with protecting property rights and sensitive ecosystems.”

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Massachusetts Transportation Bond Bill Seeks to Unlock $4B in IIJA Funds

Massachusetts Gov. Charlie Baker gave testimony Tuesday for a transportation bond bill that would unlock $4.1 billion in funding from the Infrastructure Investment and Jobs Act (IIJA) signed by President Biden in November.

The bill (H.4561) would authorize the state treasurer to issue up to $5.6 billion in bonds to ensure the state can meet federal matching requirements for varying percentages of infrastructure project costs.

“We’ve developed a plan to invest billions of dollars in communities throughout the commonwealth over the next five years using the resources from [the IIJA],” Baker said. “That’s why we filed this legislation to authorize $9.7 billion to prepare for the resources and funding that will come to the commonwealth through this bill.”

Baker signed a $16 billion transportation bond bill in January 2021 that included $4.4 billion in federal funding for the next two years. At that time, Baker said, his administration expected to ask the legislature to authorize additional funding for transportation in the near term, but passage of the IIJA altered their plans.

The IIJA “increases the annual level of federal funding that goes well beyond what we had anticipated for the next five years,” Baker said.

Baker introduced the new bond bill on March 21, declaring it an emergency measure that requires action before the end of the legislative session in July. He acknowledged that the bill creates a lot of work for the legislature in a short time and will attract an “enormous amount of interest.”

Funding in the bill includes $200 million for the Executive Office of Energy and Environmental Affairs (EEA) to implement programs for public alternative fueling and EV charging stations, e-bikes, EVs for hire or sharing, and medium-duty EV trucks.

Of the total allocation for the EEA, Baker said, $150 million is set aside for investments that promote equity and improve public health, such as EV incentives for low-income families or electric school bus purchases. EEA’s remaining $50 million allocation will be used for matching funds to help the state compete for discretionary grants.

A $1.4 billion allocation to the Department of Transportation would support modernization of the transit system, including the Massachusetts Bay Transportation Authority’s (MBTA) plan to electrify its fleet of 1,100 buses by 2040. A bill (S.2292) currently before the Joint Transportation Committee would advance the deadline for MBTA’s fleet electrification to 2030. The committee has until April 29 to report that bill to the legislature.

The DOT would receive another $43.4 million from the bond bill for projects that improve regional transit networks and facilities through, among other things, rehabilitation of facilities to support clean vehicles. Facility upgrades necessary for MBTA’s full bus fleet electrification will cost $4.5 billion, according to the authority.

Additional allocations to the DOT that support the state’s climate laws include $2.8 billion for projects on the interstate and non-interstate federal highway system, including EV charging infrastructure; and $145 million for planning across all transportation modes, including supporting reduction of greenhouse gas emissions from transportation.

To help the state compete for discretionary and grant program funding in the IIJA, the bond bill includes a $3.5 billion authorization, Baker said. While the state awaits grant program guidance, he added, “it’s critical that … we have the authorizations in place so we will be able to move quickly and efficiently to deliver additional federal funding to the commonwealth.”

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CARB Seeks More Inclusive Clean Cars 4 All

As California prepares for an expansion of the Clean Cars 4 All program, officials are working on strategies to make sure the clean vehicle purchase incentive for low-income residents goes to those who need it most.

The California Air Resources Board (CARB) has proposed a household income limit of 300% of the federal poverty level for drivers to receive the incentive under the expanded program.

But the income limit could be just one piece of a needs-based approach to the incentive, said Aaron Hilliard, manager of the Alternative Strategies Section within the Incentives & Technology Advancement Branch at CARB.

“[We’re] looking at potentially other metrics for determining who is in the greatest need, other than just income,” Hilliard said.

Hilliard’s comments came during a CARB workshop on Monday to discuss the statewide expansion of Clean Cars 4 All. CARB staff described the workshop as a kick-off meeting on program expansion, with many details yet to be ironed out.

CARB’s Anthony Poggi said the agency is looking at how it would prioritize applicants in disadvantaged communities. The strategy will include working with community-based organizations and Access Clean California, a program that helps lower-income residents find clean energy benefits for which they’re eligible.

Program implementation is another variable in the Clean Cars 4 All expansion, according to Hilliard, who said CARB has heard comments about the drawbacks of first-come, first-served vehicle incentive programs.

Air District Involvement

In Clean Cars 4 All, an eligible driver agrees to scrap their old car in exchange for an incentive to buy a new or used hybrid, plug-in hybrid or zero-emission vehicle.

The Clean Cars 4 All incentive is currently offered by four California air districts: the Bay Area Air Quality Management District (AQMD); the Sacramento Metropolitan AQMD; the South Coast AQMD, which calls the program Replace Your Ride; and the San Joaquin Valley Air Pollution Control District (APCD), which calls the program Drive Clean in the San Joaquin.

The San Diego County Air Pollution Control District is getting ready to launch the program. CARB provides funding to air districts to administer the program.

A CARB regulation currently limits Clean Cars 4 All participation to air districts with a population of 1 million or more. And drivers receiving an incentive must live in a zip code that contains a disadvantaged community census tract.

But under the statewide expansion, those restrictions would be dropped. Poggi said the statewide expansion would not affect existing programs in the four air districts or the one in San Diego. Instead, the statewide program would be complementary to those programs.

CARB plans to recruit a statewide administrator to run the expansion program. The agency expects to release a solicitation for the position in early June.

Requirements Debated

For the statewide expansion of Clean Cars 4 All, CARB has proposed a household income limit of 300% of the federal poverty limit, which works out to $65,880 for a household of three or $79,500 for a household of four. About 90% of program participants already meet this income requirement.

Beverly DesChaux, president of the Electric Vehicle Association of Central Coast California, suggested targeting the incentive to drivers whose cars are “big, fat polluters.” The size of a car, its age and how much it’s driven could be factored in, she said.

DesChaux also called for restricting the Clean Cars 4 All incentive to plug-in hybrid or zero-emission vehicles and eliminating non-plug-in hybrids from the program.

“A hybrid … is simply a gas car that has a little electric motor that boosts the mileage a little bit,” she said.

Poggi said that hybrids were being included in the statewide program to give participants options on what to buy. He noted that air districts are being given flexibility on whether to include hybrids in their programs.

LaDonna Williams, programs director with All Positives Possible, a non-profit organization promoting disadvantaged communities’ right to a clean environment, said CARB’s proposed changes would make Clean Cars 4 All more inclusive.

Disadvantaged and low-income populations, particularly African-American communities, have fallen through the cracks in the past, she said.

Williams also cautioned against dictating drivers’ choice of car, even if a polluting vehicle might be offensive to some. Not everyone has money to cover the expense of a newer car, she said.

“Because we see someone driving a big vehicle or a gas car, that might be our personal opinion, but we also don’t want to end up being policed,” Williams said. “Because, again, at the end of the day, we know what population is going to be targeted the most for that, so we want to keep these options open.”

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NERC Director Joins WECC Exec Team

WECC said Tuesday that Steven Noess, NERC‘s director of regulatory programs, will join the West’s regional entity as its new vice president of reliability and security oversight beginning April 29.

Noess will take over a role previously filled by Steve Goodwill, who last fall became WECC’s senior vice president of strategic engagement.

At NERC, Noess leads a working group that supports “the alignment, effectiveness and oversight” of the Compliance Monitoring and Enforcement Program (CMEP) activities within the ERO Enterprise, according to a WECC release.

He recently co-led a team of 50 experts on the FERC-NERC inquiry into the February 2021 cold weather event that caused numerous outages and derates across Texas, leading to the largest manually controlled load-shedding event in U.S. history. (See FERC, NERC Release Final Texas Storm Report.)

In his new position, Noess will oversee development of WECC’s own CMEP and manage teams within the RE’s Oversight department, including Entity Monitoring, Risk Assessment and Registration, and Enforcement and Mitigation.

“Steve [Noess] brings in-depth oversight knowledge to the role, which will enable him to immediately take the lead in this critical position,” WECC CEO Melanie Frye said Tuesday in a statement. “His extensive ERO Enterprise-wide regulatory knowledge, coupled with his ability to successfully collaborate with external stakeholders to achieve reliability goals, will be an additional asset for WECC.”

Noess joined NERC in May 2011 as a standards developer, a position in which he led efforts to complete version 5 of the ERO Enterprise’s Critical Infrastructure Protection program, according to his LinkedIn profile. He was subsequently promoted to the roles of director of standards development and director of compliance assurance and program oversight before taking on his current position.

Prior to joining NERC, Noess was an attorney at the Minnesota legislature, where he managed development of legislation related to economic development, employment law and business and professional codes/licenses. He also helped develop administrative rules for executive branch agencies. He previously served as a captain in the U.S. Army and was deployed to Iraq in 2003, where he was awarded a Bronze Star.

Noess is a graduate of the U.S. Military Academy at West Point and holds a Juris Doctor from the University of Minnesota.