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November 18, 2024

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Oregon Moving Quickly to Adopt Advanced Clean Cars II Rules

Oregon regulators are racing to adopt by the end of the year a California rule requiring all new cars sold in the state to be zero-emission or plug-in hybrid by 2035.

Adoption this year would mean that the rule, known as Advanced Clean Cars II, would take effect starting with vehicle model year 2026. The regulation would require car manufacturers to provide an increasing percentage of ZEVs for sale each year, beginning with 35% in 2026.

The California Air Resources Board voted to adopt the regulation last week. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

In Oregon, the Department of Environmental Quality held its first meeting of the Advanced Clean Cars II Rule Advisory Committee on Tuesday. Rachel Sakata, a senior air quality planner at DEQ, said the agency expects to release the rule for formal public comment in September.

The proposal would then go to the Environmental Quality Commission for potential adoption in December, Sakata told the committee.

Oregon is one of 17 states that have adopted California’s current Advanced Clean Cars regulation, which covers new vehicles through model year 2025. Under the Clean Air Act, states may choose to follow federal vehicle emission standards or adopt regulations that are essentially the same as those of California.

There’s a rush to adopt the new Advanced Clean Cars II by the end of this year because of a two-year waiting period that’s required before the regulation can take effect. Model year 2026 vehicles will be released starting in 2025, Sakata noted.

Infrastructure Concerns

Committee member Greg Remensperger, executive vice president of the Oregon Auto Dealers Association, said dealers support the transition to electric vehicles, although some have concerns about how quickly they’ll face the 100% sales requirement.

Remensperger said he will recommend a mid-term review of ACC II to see if the pieces needed for the program’s success are falling into place.

“[If] we implement the rules as stated and the availability isn’t there or the cost is too expensive or the infrastructure is not there to support it, it’s just going to drive consumers to leave the state to buy … the ICE vehicle and bring it back into Oregon,” Remensperger said.

Not everyone at the meeting was on board with the proposed ACC II regulation. Oregon Rep. David Brock Smith (R) said the proposal is “not well thought out” when it comes to factors such as having sufficient transmission and capacity.

“That is why it’s the legislature that should be directing these policies and not rulemaking through agencies,” said Smith, adding that he will propose legislation to “unwind” the rulemaking work.

Jumping to 35%

The current Advanced Clean Cars regulation, which Oregon has adopted, also includes a ZEV sales requirement that increases each year, topping off at 22% for model year 2025.

However, ZEV credits are calculated differently in the current regulation as compared to ACC II. In the existing system, credits are based on factors, including the electric range of a vehicle, with some ZEV models receiving multiple credits per vehicle.

ACC II will use ZEV “values” rather than credits. One zero-emission vehicle will equal one value.

Despite the differences, Sakata acknowledged it will be a “jump” for car manufacturers to meet the 35% ZEV requirement in 2026. But automakers will have a variety of tools to help close the gap, she said. Those include the ability to carry over credits earned under the current Advanced Clean Cars rules, an early credit system and a system for transferring credits between ACC II states.

And under ACC II, manufacturers can meet up to 20% of their ZEV requirement with plug-in hybrid vehicles.

In addition, manufacturers can take advantage of voluntary environmental justice credits, which will be awarded for actions such as providing low-priced ZEVs for sale in model years 2026 through 2028. The ZEVs or PHEVs must have an MSRP of $20,275 or less for passenger cars and $26,670 or less for light-duty trucks.

States adopting California’s ACC II rule will have some flexibility in implementing environmental justice credits. That’s a topic on which the advisory committee will provide input.

Moving Forward in 2022

Oregon is one of four states, along with Washington, Vermont and Massachusetts, that have said they intend to adopt ACC II by the end of this year, according to a blog post from the Natural Resources Defense Council. Several other states may follow suit in 2023.

For example, Nevada published an initial draft regulation on June 30 as a first step toward adoption of ACC II. The Nevada Division of Environmental Protection plans to analyze potential costs and benefits of the regulation and receive public comment before bringing it to the State Environmental Commission for possible adoption next year.

NDEP expects to release more details on the process in coming weeks, the agency told NetZero Insider.

In Oregon, the Advanced Clean Cars II Rule Advisory Committee will hold a second meeting on Sept. 20 to review statements of fiscal, economic and racial equity impacts of the rule.

Informal comments may be submitted to the committee until Sept. 7 at noon. More information on the ACC II rulemaking is here.

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Granholm Says DOE Keeping an Eye on Winter Fuels

The federal government is standing ready to help New England with fuel supply and grid reliability this winter, Energy Secretary Jennifer Granholm told the region’s governors in a recent letter.

Granholm’s letter came in response to the states’ request for help, in which they asked the Biden administration to consider a waiver of the Jones Act for LNG deliveries, proposed a new energy reserve system for the region and asked for coordination ahead of what could be a difficult winter. (See New England Governors Ask Feds for Help with Winter Reliability.)

At the Department of Energy “and across the Biden administration, we recognize that the New England states face unique energy challenges, and your letter raises important areas for continued coordination and new collaboration with the administration,” Granholm wrote.

She said DOE is monitoring prices and inventory levels of natural gas, gasoline and distillates, and that she has been meeting with domestic producers and refiners to talk about their inventories and preparedness for storms.

On the East Coast, inventories are 20% below the seasonal five-year average for gasoline and 47% below the seasonal five-year average for distillates. In New England, diesel inventories are 63% below their five-year average.

“These data points raise concerns about the impact of any physical disruption of supply and require that both states and the federal government are prepared to use all the tools in our toolkit to improve preparedness and respond if needed,” Granholm wrote.

But while she offered general assurances that the federal government is on the case, she didn’t directly agree to any of the governors’ specific asks.

Granholm noted that requests to waive the Jones Act, which requires that ships hauling cargo between U.S. ports be built in the U.S., are handled by the Department of Homeland Security, and that the department would “expeditiously consider” individual waiver requests that come in. The governors had asked for a broader suspension of the Jones Act for winter LNG deliveries.

She also said that DOE “welcomes” the thoughts of governors on modernizing strategic energy reserves but gave no indication that her department is working on the subject itself.

She did say, however, that DOE and the states should “consider if a minimum fuel stock holding requirement for liquid fuels is a necessity moving forward.”

FERC is leading a meeting in Vermont next week to discuss winter reliability issues in New England. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

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SPP’s Markets+ Offering Attracts 6 More Western Entities

SPP said Monday that six more Pacific Northwest entities are interested in participating in the next phase of the grid operator’s energy market services in the Western Interconnection.

The six organizations — Avista, Chelan County Public Utility District (Wash.), Grant County Public Utility District (Wash.), Puget Sound Energy, Tacoma Power and Canadian marketer Powerex — made their intentions public in an Aug. 19 letter to SPP, saying they intend to work with the RTO to develop a Western market that “supports reliability and delivers value to our customers.”

They join Bonneville Power Administration in formally committing to funding the further development of Markets+, a conceptual bundle of services that would centralize day-ahead and real-time unit commitment and dispatch and provide hurdle-free transmission service. Markets+ has been framed as a voluntary, incremental opportunity to realize market benefits by utilities that aren’t ready to pursue full RTO membership. (See BPA Commits to Funding Markets+ Development.)

SPP said the seven entities willing to move forward with the development of Markets+ represent a “well connected footprint with extensive transmission capability, a large fleet of clean flexible hydro resources and a peak load” of over 30 GW. That is 50% larger than ISO-NE, the nation’s smallest grid operator, it said.

“We are very encouraged by the governance and market design progress for Markets+ over the past several months, which has been achieved through SPP’s collaborative, stakeholder-driven approach,” Powerex CEO Tom Bechard said in a statement.

Powerex Managing Director Mark Holman has been one of the most vocal and inquisitive participants in SPP’s Markets+ development sessions, which began late last year. The grid operator has held three in-person meetings with Western stakeholders to review work on the market’s service offering and discuss outstanding items and next steps. (See SPP Continues to Build on Markets+ Offering.)

“By participating in this process, we are working together to build Markets+ on a strong foundation of input from Western stakeholders, ensuring the market meets the needs of the West and brings value to all participants,” SPP CEO Barbara Sugg said.

A draft service offering that explains how the proposed service will address governance structure, market design, transmission availability and other items will be distributed Sept. 30, setting off a public comment period. The final service offering will be distributed Nov. 18. Interested parties will make a commitment to fund further market development in early 2023.

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MISO Gathering Stakeholder Input on LRTP Cost Allocation

MISO is collecting stakeholder suggestions on the design elements that should be included in a new cost allocation for some of the long-range transmission planning (LRTP) projects.

Milica Geissler, the RTO’s cost-allocation specialist, said Tuesday the goal is to create by the end of 2023 a methodology to allocate costs for the third and fourth LRTP portfolios. She said the design could be used footprint-wide or exclusively for MISO South.

During a meeting of MISO’s cost-allocation stakeholder group, Geissler said staff is looking to balance “granularity, feasibility and consistency” in the cost-sharing design.

“The most accurate reading for some benefits may be at the MISO footprint or sub-regional-level,” she said, advising against stakeholders expecting cost-benefit calculations at the transmission pricing-zone level.

MISO is using a 100% postage stamp rate for the first two LRTP project cycles, with those costs confined to MISO Midwest. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.) When planners begin looking for long-range projects in MISO South, the grid operator plans to use a more specific cost-allocation design. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

Some stakeholders have voiced concerns of disparate treatment between LRTP portfolios, saying a different cost allocation for MISO South projects will violate FERC’s principle that inconsistent allocations must not be applied to the same class of projects.

At any rate, the new cost allocation might contain cost assignments for interconnecting generation in addition to load.

Darcy Neigum, with Montana-Dakota Utilities Co., proposed that the RTO impose long-range transmission costs on interconnecting intermittent resources only. He said MISO could include a new intermittent generation MWh value in the denominator when calculating LRTP project rates.

Neigum said assigning a portion of long-range transmission costs to intermittent resources would “align cost-causers and beneficiaries.” He said states and utilities with carbon-reduction goals are driving the generation fleet change that necessitates the transmission in the first place.

“Not all states and loads are equal cost causers and beneficiaries,” he said.

Clean Grid Alliance’s Natalie McIntire raised concerns that only intermittent generators would bear the lines’ costs. She said thermal generation will benefit from long-range projects as well.

McIntire also argued that the LRTP’s primary purpose is to ensure grid reliability through the resource transition, and not to simply accommodate generator interconnections.

Sustainable FERC Project attorney Lauren Azar said Montana-Dakota Utilities’ proposal “gave her pause.”

“LRTP is not only responding to the challenges of changing grid … but extreme weather events as well. The fact of the matter is that resilience is a goal of LRTP, and everyone in MISO Midwest will benefit,” Azar said.

MISO stakeholders will next discuss LRTP cost allocation during an Oct. 18 meeting.

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NJ Eyes Rules to Protect, Gather Advanced Metering Data

New Jersey is studying how to set data-gathering rules to ensure that the growing implementation of advanced metering infrastructure (AMI) helps ratepayers cut energy use and support efforts to meet the state’s ambitious clean energy goals.

The state’s Board of Public Utilities (BPU) will hold a second hearing on Sept. 6 into its straw proposal intended to ensure that ratepayers and other stakeholders can get speedy, accurate data on which to make energy decisions while protecting the privacy of consumers and securing the system.

State officials believe AMI is an important element to implementing Gov. Phil Murphy’s Energy Master Plan, which sets a state goal of 100% clean energy by 2050. It calls AMI a “foundational component of a modernized electric distribution grid” and describes it as “a prerequisite of many additional clean energy objectives.”

AMI is the use of “smart” meters that can compile data on a ratepayer’s energy use and transmit it to the user or third party, often in real time. Analysis of the data can help the ratepayer adjust their energy use, facilitating changes such as shifting the time of day for completing tasks to when energy is cheaper, halting some practices or allowing the user to switch away from high energy-consuming appliances.

The first utility in the state to implement an AMI strategy, Rockland Electric Co., installed about 74,000 smart meters by 2019. The state expects its other three utilities to deploy more than 3.9 million smart meters over the next five years.

Benefits of AMI

The straw proposal, released a year ago, would create a standardized system of rules that govern how utilities handle issues such as data sharing, data access, data privacy and billing reconciliation. The state’s four utilities would each be required to file data access plans to implement the rules.

AMI “holds the potential to be an integral part of New Jersey’s clean energy transition, enhance retail competition and efficiencies, and enable customers to better understand and control their own energy usage,” the proposal says.

The straw proposal emphasizes that the data, although often collected by the utility, are owned by ratepayers, who should control who can access them and whether that should include third parties. The BPU’s plan recommends the use of the “Green Button Connect” system, a standardized, relatively user-friendly system through which ratepayers can access their own data through a green button on their utility company’s website. The proposal also would require utilities to follow standard cybersecurity measures to protect the data.

Metrics that should be collected, according to the proposal, include: total usage and demand in kilowatt-hours, the number of customers who access the data, and how many customers sign up for energy-saving tools, energy-usage information and saving tips.

Speakers told the first hearing on the proposal Aug. 16 that the speed at which data become available is important to ensuring their value and to keeping consumers focused on their energy usage.

“Energy data is a highly fungible commodity whose value is maximized when accessed and interpreted shortly after the energy consumption,” said Christopher Oprysk, an engineer at the BPU who presented parts of the proposal at the hearing. “Consumers are more likely to respond with behavior changes if the data reflects recent consumption patterns and more closely ties [it] to cause and effect.”

The proposal argues that “billable data,” which are collected by the utilities to calculate ratepayer bills, should be available within 48 hours and customers should be provided with an energy monitoring device that would make available unvalidated data within 15 seconds, which could be accessed through a home area network.

Murray Bevan, a lobbyist for several energy suppliers, including NRG Energy and Vistra, echoed the point, telling the BPU that rapid access to data is critical.

“If I run my dishwasher at 4 in the afternoon, or I run it at 10 at night, there’s like a 40% difference in the price of running it,” he said. “So if I really need the clean dishes for dinner at 6 or 7, OK, I’ll go ahead and run it. But if I can wait until 10, that’s a significant price win.”

“Getting the data as close to the real time usage as possible, is the most valuable,” he said. “If I’m making this decision on Monday, and I’ve learned about it, that I should have run the dishwasher at 10, on Tuesday or Wednesday, obviously that’s not as valuable to the customers.”

AMI Implementation Surge

The BPU in January gave approval to a plan by Public Service Electric and Gas to invest $700 million over the next four years to provide smart meters to its 2.3 million electricity customers. The company at the time said the move would “help expedite electric service restorations when severe weather strikes, help customers increase their home energy savings and improve service quality.”

In July 2021 the board approved a plan a plan by Atlantic City Electric to spend $177 million on installing 565,000 smart meters. And the state’s fourth utility, Jersey Central Power & Light, has a plan before the BPU to spend $360 million on AMI.

Yet the state’s adoption of AMI has lagged, even as other states have embraced the technology. There were 94.4 million advanced meters in operation as of 2019, the latest that figures are available, according to FERC’s annual Assessment of Demand Response and Advanced Metering report released in December. That accounted for 60.3% of the meters of all types operating in the country and was an increase of 8 million smart meters over the year before, the report said.

The Mid-Atlantic region had the second worst penetration in the nation, with only 37.4% of the meters being advanced, the report said. The worst was New England, with 22% penetration, while the highest penetration was in the West South Central Region, which includes Texas, and the Pacific region, both with about 74% penetration.

Yet even those areas in which AMI penetration is high, the technology may not be fully used, according to a study that Mission:data, a nonprofit advocacy organization that works to promote AMI usage, is set to release next week. More than a decade after the federal American Recovery and Reinvestment Act (ARRA) disbursed $3 billion for AMI projects, “most of the data-access benefits promised to customers have been deactivated,” the report says. Only about 2.9% of the 17.4 million advanced meters funded by the program are enabled, the report says.

Still, New Jersey’s slow uptake could end up helping the state, said Michael Murray, president of Mission:data. The state can learn from projects in other states where “customer benefits of smart meters have not materialized,” he said in an interview with NetZero Insider. And the state’s program could be bolstered by the recently enacted Inflation Reduction Act, which includes funds that can be used for AMI, he said.

While some consumer advocates are skeptical that the benefits from AMI are worth the investment, a dozen studies have shown that “6 to 18% energy savings are possible when consumers have easy, electronic access to their meter data,” he said. Aside from helping customers cut energy use, AMI data can help them buy the right size of appliance they need based on actual electricity use and can help with the purchase of energy-efficient equipment such as heat pumps.

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MISO Recommends Lower Distribution Factor to Address Congestion

To cut down on its surging congestion, MISO is suggesting a tighter limit on how much new generation can affect the surrounding grid without triggering more network upgrades.

The grid operator announced it is considering halving new generation’s allotted distribution factor impact on transmission from 20% to 10% for its basic level of interconnection service, called energy resource interconnection service (ERIS).

Some MISO members maintain that interconnecting generators are unacceptably raising congestion and a narrower distribution factor threshold would keep runaway congestion in check by flagging a need for more transmission upgrades.

MISO said a preliminary analysis showed that lowering the distribution factor for ERIS to 10% identified “several” new network upgrades in its annual interconnection queue cycles, “the majority being in the 69 to 161 kV voltage range.”

Interconnection customers can either elect to secure ERIS, or the higher-quality network resource interconnection service (NRIS), which ensures that the entire installed capacity of resources is deliverable. NRIS is generally more expensive than the unguaranteed ERIS.

MISO said ERIS elections from new generation “can lead to more congestion on the transmission system.” It said a lower distribution factor cutoff could result in fewer system reliability issues and have more interconnection customers sharing in network upgrade costs.

The RTO now faces billion-dollar congestion costs on a quarterly basis. MISO’s long-term transmission plan is set to assuage some of that congestion, but the first in-service dates of the 18 new lines are at least eight years out.

Meanwhile, the grid operator is again bracing for a historic level of interconnection requests in its 2022 queue cycle. During an Aug. 30 transmission cost allocation meeting, MISO’s interconnection team estimated the RTO will field about 700 new interconnection requests totaling about 100 GW in a few weeks.

MISO staff also said they’ve been receiving complaints from new generators that have interconnected but cannot get their output delivered on the system due to transmission congestion.

Some of MISO’s clean energy advocates have said lowering the distribution factor threshold seems punitive to renewable energy, which makes up the overwhelming majority of MISO’s interconnection queue.

At a mid-August Interconnection Process Working Group, Xcel Energy’s Randy Oye said increased expenses for new generation isn’t a valid argument against lowering the distribution factor threshold. He said if a project stands to affect lines by 20%, then the project’s business case might need to be reexamined.

“The load is going to pay $10 billion for transmission. I think a fair question is: what should generation pay?” he said, referring to the cost of MISO’s recently approved long-range transmission portfolio.

Stakeholders asked for some sort of MISO demonstration that lowering the distribution factor threshold will in fact reduce congestion. They also criticized MISO for concocting a policy change in secret before bringing a proposal to a stakeholder meeting.

MISO’s stakeholder community is again set to again debate a stricter distribution factor at an Oct. 10 Interconnection Process Working Group meeting.

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MISO Cancels Hartburg-Sabine Competitive Project

A MISO staff planning committee has determined that MISO South’s only competitive transmission project, the $130 million, 500-kV Hartburg-Sabine Junction project in East Texas, is no longer necessary.

The decision wasn’t surprising. MISO has been warning for months that its analysis indicated that the project was no longer helpful to the system. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

The project’s cancellation comes as the 5th U.S. Circuit Court of Appeals Tuesday ruled that Texas’ right-of-first-refusal (ROFR) law violates the U.S. Constitution’s dormant Commerce Clause. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

Brian Pedersen, senior manager of competitive transmission administration, said the RTO is evaluating the opinion for possible impacts to Hartburg-Sabine. However, “the opinion and order does not change the planning analysis,” he told stakeholders Wednesday during a Planning Advisory Committee meeting.

Pedersen added that MISO isn’t planning to conduct any more economic or reliability analyses on the project. He said studies have already shown the project has “near-zero” production cost benefits and did not uncover any transmission system issues without the line.

The grid operator said the project’s benefits dissolved because of recent Entergy generation additions near the line’s route. The utility brought the 993-MW Montgomery County Power Station online in 2021, and it intends to construct the 1.2-GW natural gas- and hydrogen-powered Orange County Advanced Power Station by 2026.

MISO approved the market efficiency project as part of its 2017 Transmission Expansion Plan, based on expectations it would alleviate congestion, ease import limitations and allow access to lower cost generation for customers in the chronically congested West of the Atchafalaya Basin and western load pockets in Entergy’s MISO South footprint.

“It’s been a little over four and a half years since the project was approved,” Pedersen reminded stakeholders.

In 2018, MISO selected NextEra Energy Transmission Midwest’s bid for a new 23-mile, 500-kV transmission line, four short 230-kV lines and a new 500-kV substation. NextEra’s proposal beat 11 other competitors. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

However, Texas later passed a law in 2019 giving incumbent utilities ROFRs for any projects built in the state. With NextEra unable to secure permitting for construction and the 2023 in-service date approaching, MISO this year initiated its variance analysis, a process used to reanalyze projects that experience material changes. Following the analysis, the RTO had two choices: cancel the project or reassign it to a new developer.

“MISO always has deference to states’ rights in these types of matters,” director Mark Johnson explained in 2019.

MISO’s bid selection report is now considered moot. The grid operator now plans to file with FERC in the fourth quarter to terminate its selected-developer agreement with NextEra.

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Maine Court Ruling Gives New Life to Contentious Transmission Line

Maine’s highest court on Tuesday ruled that a referendum blocking the New England Clean Energy Connect (NECEC) transmission line may have been unconstitutional, reigniting hopes that the fiercely opposed project could get built after all.

In a 39-page ruling, the Maine Supreme Judicial Court found that part of the ballot question could be invalid because it retroactively applies new laws to the certificate of public convenience and necessity obtained by the project’s developer Avangrid (NYSE:AGR) and its subsidiary Central Maine Power.

It sent the case back to the Maine Business and Consumer Court for “further proceedings consistent with this opinion.”

The ruling is the latest twist in a consequential saga that some clean energy advocates say will shape the future of New England and determine how quickly the region can wean itself off fossil fuels. The line, which would bring energy from hydropower plants in Quebec into New England and is central to Massachusetts’ clean energy plans, has been at the center of legal and political battles for years.

It received a signoff from the federal government in early 2021, only to be shot down by Maine voters in a referendum later that year in which 59% voted to ban the construction of “high-impact” transmission lines in the area and require approval from the legislature for future such projects.

The constitutionality of that ballot initiative has been the last-gasp hope of the project’s developers, and Maine’s highest court came to their aid on Tuesday.

“Our analysis and conclusions are not based on the wisdom of either the project or the [ballot] initiative,” the five-judge panel wrote. But the initiative would “infringe on NECEC’s constitutionally protected vested rights” if the project can show that it engaged in “substantial construction” on the authority granted by the certificate it was granted before the initiative was approved by Maine voters.

ClearView Energy Partners called the ruling a “significant win” for NECEC, but it noted that there are other risks pending.

“We view today’s opinion as constructive to CMP’s plans to complete the project, but the project developer has not yet overcome all its legal challenges,” ClearView’s analysts said.

Those include a separate case about a lease from the Bureau of Parks and Lands, a suspended permit from the Maine Department of Environmental Quality, and judicial challenges to two federal permits by environmental groups.

But those remaining challenges didn’t stop Avangrid from breathing a sigh of relief.

“This unanimous decision by the law court is a victory for clean energy expansion, transmission development and decarbonization efforts in Maine, New England and across the country,” Avangrid said in a statement.

The company said the project has faced opposition from fossil fuel-fired generators at every step.

“It is time to move away from the status quo fossil fuel companies who will undoubtedly continue their fight to maintain a stranglehold on the New England energy market,” Avangrid said. “These companies have fought this clean energy project in every legal manner possible, filing challenge after challenge in a desperate effort to hold onto their share of the market. Maine’s highest court has rejected their latest challenge as unconstitutional.”

The ruling was also celebrated by the transmission trade group WIRES.

“Today’s decision by the Maine Supreme Court will hopefully set the important NECEC project back on track, although with likely further delays,” WIRES Executive Director Larry Gasteiger said, calling the project a “poster child for how difficult it is to get needed transmission built.”

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Northwest States Collaborate to Win Hydrogen Hub

Washington, Oregon and Idaho are preparing a joint proposal to become a regional hydrogen manufacturing and distribution hub.

The three state governments — acting as leaders of the public-private Pacific Northwest Hydrogen Association — aim to have a proposal ready sometime in September to submit to the U.S. Department of Energy to obtain part of $8 billion in federal funding being made available to develop hydrogen hubs nationwide.

On Monday, the association announced that its 18-member board elected Washington Department of Commerce Director Lisa Brown as its chair and Oregon Department of Energy Director Janine Benner as vice-chair. Idaho’s government is represented in the group’s Advisory Committee.

“We understand how green hydrogen fits into a modern, decarbonized economy that is possible today — no other region is as advanced in this area,” Brown said in a press release.

“This work will lay a foundation for this important decarbonization fuel in our region — one that can help us meet our mission to shape an equitable clean energy transition for Oregon and beyond.”

Other interests represented on the board include the Douglas County Public Utility District, Tacoma Power, several labor unions, some hydrogen and environmental organizations, Amazon, BP America, Puget Sound Power, plus the Chehalis and Cowlitz tribes. Several research organizations and labs, including the Pacific Northwest National Laboratory, also participate in the association.

The association’s board also includes a representative from Australia-based Fortescue Future Industries, which is exploring building a green hydrogen plant on the site of a disused coal mine in Centralia, Wash. (See Australian Company Eyes Wash. Coal Mine as Green Hydrogen Site.)

This alliance wants to tap into the $8 billion fund that DOE has set aside to create four to eight regional hydrogen hubs across the nation. Each hub would get $1 billion to $2 billion. Washington, Oregon and Idaho are aggressively pursuing that money.

DOE expects to receive roughly 100 proposals by September. No timetable is set for the agency’s decisions on how to allocate the $8 billion.

In Washington, one hydrogen manufacturing plant owned by the Douglas County PUD is scheduled to go online in East Wenatchee in mid-2023. The Port of Seattle is also studying whether it wants to get into hydrogen manufacturing and distribution. Refueling stations for hydrogen-powered vehicles are in the works for East Wenatchee and the transit authority in Chehalis and Centralia

Meanwhile, Obsidian Renewables of Lake Oswego, Ore., plans to build hydrogen production plants at existing industrial parks in Hermiston, Ore., and Moses Lake, Wash. These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in eastern Washington behind Spokane. (See Company Looks to Build Hydrogen Projects in Eastern Ore., Wash.)

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FERC Issues Deficiency Letter on PJM Queue Overhaul

FERC issued a deficiency letter Tuesday seeking more information on PJM’s proposed overhaul of its interconnection queue process (ER22-2110).

With a ballooning backlog in its interconnection process and a sharp increase in new service requests, PJM is seeking to switch from its current “first come, first served” system to a “first ready, first served” queue. The proposal would cluster service requests together for both interconnection studies and cost allocation and advance applications making demonstrable progress toward operability. (See PJM Files Interconnection Proposal with FERC.)

The Aug. 30 letter from FERC’s Office of Energy Market Regulation asks for further information on several points of the tariff revision, largely having to do with how the new procedures would operate and comply with past FERC orders. A response is due from PJM within 30 days.

The letter questions if grouping all applications from Oct. 1, 2021, with those received through the processing of the first new cycle could create a risk of the first wave of projects evaluated under the new system becoming “unmanageably large” and how the RTO would address that possibility.

The removal of two sections of the tariff related to reporting and penalties for PJM should it fail to complete a set percentage of transmission service request studies within a certain timeframe caught FERC’s attention, with the commission seeking an explanation of how the removal would be “consistent with or superior to” the current requirements under Order 890.

The letter also seeks more information on the RTO’s plan to consolidate interconnection procedures for both small and large generators.

Staff also asked the RTO to explain how it will determine whether a request for long-term firm service can be studied as part of the planning process for bulk transmission supply in PJM or whether special impact studies must be completed.

And it asked for clarification of PJM’s proposal to allow a project developer to change the project site from one location to an “adjacent parcel,” asking whether they must be contiguous or merely in the same geographic area.

Tariff Revisions Supported by Stakeholders

The revisions to PJM’s tariff were submitted to FERC June 14 after receiving strong endorsement from the RTO’s stakeholders in April.

The RTO has stated that its proposal is comparable to the interconnection processes employed by SPP, MISO and PacifiCorp. The new system would add multiple decision points at which applicants would be required to make readiness deposits and meet other requirements to continue.

Currently, less than 20% of applications make their way through the queue and become operational.

Not all projects drop out because of the length or difficulty of the process. Many projects are speculative “price discovery” requests submitted to determine where interconnection costs are least expensive.