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October 31, 2024

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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. 

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NYISO Details 2023 Budget & Compensation Updates

NYISO is proposing a $32 million project budget for 2023, a $5 million reduction from this year’s spending.

NYISO’s Brian Hurysz, who presented the final project recommendations for the 2023 budget to the Budget and Priorities Working Group (BPWG), said 13 of the 24 projects that had been identified as stakeholder priorities were included in the spending plan.

The $31.98 million budget includes $13.7 million for labor, $9.7 million for capital and $8.5 million for professional services, $5.2 million lower than the 2022 project budget of $37.2 million. The 2022 budget increased project spending by $10.7 million over 2021 largely because of the Alternate Control Room Renovation project, which was deferred from 2021, and the Distributed Energy Resource Integration project.

The market and enterprise budget recommendations were $11.36 million and $20.62 million, respectively. 

In addition to deferring 11 of the 24 proposed market projects, including the duct firing modeling that NYISO desired, the ISO is recommending cost savings or scope changes for some projects:

  • The Distributed Energy Resources (DER) Participation Model will be delayed, with deployment planned later in 2023. The cost of the project has increased, and the operational enhancements have been reduced.
  • Storage as Transmission, requested by stakeholders, will be limited to “issue discovery” — education sessions and identification of potential solutions for future ranking — in 2023.
  • Capacity Resource Interconnection Service (CRIS) Expiration Evaluation & CRIS Tracking: CRIS Tracking will be deferred to 2024; CRIS Expiration Evaluation will develop CRIS Tracking requirement updates and be implemented with CRIS Tracking in 2024.
  • FERC Order 2222 Compliance: Scope of the project has increased based on updated information from FERC. The ISO recommends changing commitment from completed documentation of Functional Requirements (FRS) to Market Design Concept Proposed (MDCP).
  • Balancing Intermittency & Dispatchability and Fast Response Product: The ISO proposes combining some of the Dispatchability and Fast Response scope with the Balancing Intermittency, which was recommended in Potomac Analytics’ State of the Market (SOM) project.
  • Unified Communications Platform: The ISO recommends deferring the work until 2024, saying the equipment to be replaced is not end-of-life in 2023.
Proposed market projects (NYISO) Content.jpgNYISO is recommending deferring 11 of the 24 proposed market projects for 2023 and cost savings or scope changes for others. | NYISO

 

NYISO said stakeholder feedback on the budget can be emailed to Hurysz.  

The ISO’s full 2023 draft budget will be presented at the Sept. 15 BPWG meeting and the Sept. 28 Management Committee meeting.

Compensation Benchmarking Study Boosts Pay for 300 ISO Staffers

NYISO will spend $2.5 million in 2022 to raise the salaries of about 300 non-executive employees in response to a benchmarking study commissioned to address increasing attrition.

NYISO Chief Financial Officer Cheryl Hussey said the ISO hired consulting firm Mercer to conduct the study after seeing an increase in attrition and the number of people rejecting the ISO’s job offers.

Cheryl Hussey (NYISO) Content.jpgNYISO Chief Financial Officer Cheryl Hussey | NYISO

Mercer reviewed compensation data on 525 employees in 247 job titles and found that certain positions — including entry-level grid operators, engineers, software developers, IT security and infrastructure analysts and technical specialists — “trended significantly below the market,” Hussey said.

The ISO agreed to spend $2.5 million to raise “about 300” such employees to the mid-point of their peer group, retroactive to July 1, she said. The cost of the adjustments will be about $5 million for 2023.

The ISO will use nearly half of its $10.7 million 2021 budget surplus to fund these raises and a prior 3% raise given to non-executive staff retroactive to Jan. 1.

Hussey said the ISO would continue monitoring market trends and adjust salary levels again if warranted. “More recently we have had more success in our recruiting. Our vacancy rate is down. But it’s really soon to show a significant change resulting from the latest salary adjustments,” she said.

Barring additional compensation adjustments, the remaining $5.7 million from 2021’s budget surplus would be used to pay down the principal on outstanding debt, which is expected to total $82.5 million at the end of 2022.

Four Projects in 2023 Budget from Consumer Impacts Analysis

The ISO’s Tariq Niazi said that the ISO is recommending four projects be included in the 2023 budget based on its consumer impact analysis:

  • Balancing Intermittency (SOM): The project will examine existing ISO market structures and rules to help identify changes needed to maintain system reliability, while addressing the state’s climate goals cost effectively.
  • Locational Capacity Requirements (LCR) Optimizer Enhancements: Will seek improvements to the LCR methodology to improve stability and transparency.
  • Long Mountain PAR Operating Protocol: The ISO will develop an operating protocol with ISO-NE for the phase angle regulator (PAR) planned for the Long Mountain-Cricket Valley 345-kV intertie, an upgrade from the AC Public Policy Segment B project.
  • Modeling Improvements for Capacity Accreditation (SOM): Continues the work of the Improving Capacity Accreditation project to allow consideration of reliability risks such as correlated fuel unavailability and long start up notifications not modeled by the current resource adequacy analysis software.

The ISO looks for projects that are anticipated to have a net production cost impact of $5 million or more per year; have an impact of more than $50 million per year on consumer energy or capacity market prices; incorporate new technologies into ISO markets for the first time; support a new type or category of market product; or create a mechanism for out-of-market payments for reliability.

Stakeholders expressed skepticism about the ISO’s proposal to improve the modeling used by the resource adequacy analysis software GE MARS. Stakeholders said this proposal “missed the mark” since GE MARS represented such a small amount of the total resources used by NYISO. In response, Niazi stated that he would take these concerns back to his team to reevaluate. But he stressed that having accurate accreditation calculations was critical to reducing costs and improving reliability.

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FERC Rules for SPP in AECI Dispute

FERC last week ruled in favor of SPP in its dispute with Associated Electric Cooperative, Inc. (AECI) over emergency energy transactions during the February 2021 winter storm, finding that the RTO properly compensated the cooperative in accordance with its tariff (EL22-54).

In its Aug. 22 order, the commission also granted SPP’s request that FERC assert exclusive or primary jurisdiction over the emergency energy sales from AECI. FERC ruled the emergency transactions were made under a commission-jurisdictional tariff and said, “Therefore, the sales fall within the commission’s jurisdiction to regulate.”

SPP filed the request in April, asking FERC to act expeditiously to preserve its exclusive jurisdiction over the issues in dispute, given that AECI took its complaint in February to the U.S. District Court for Western Missouri (6:22cv3030). (See “SPP Takes AECI Dispute over Winter Storm Charges to FERC,” SPP Briefs: Week of May 2, 2022.)

At issue is SPP’s compensation for AECI’s emergency assistance during the winter storm. The Missouri cooperative sold power into SPP’s real-time balancing market and submitted respective tags for the transactions. The RTO settled each of AECI’s transactions over Feb.15-19 using the real-time balancing market locational marginal pricing.

The cooperative is seeking to recover $37.64 million from SPP for the emergency power it provided during the storm. That includes $29.4 million for the costs to provide the power and $8.24 million in day-ahead residual unit commitment make-whole payments SPP has charged the cooperative.

SPP’s Market Monitoring Unit intervened in the docket and asserted that FERC “unquestionably has primary jurisdiction” over the amounts SPP paid to AECI for emergency energy. The Monitor said that contracts for wholesale power sales must be filed at FERC and that there are no oral agreements for wholesale power sales. It also argued that the emergency energy transactions were not oral agreements but instead were conducted under the SPP-AECI joint operating agreement and the RTO’s tariff.

In a separate order, FERC denied AECI’s waiver request of SPP’s 365-day limitation period for modifications to settlement statements in its attempt to reach a settlement with the grid operator (ER22-2136).

The commission had twice previously granted AECI 60-day extensions to allow extra time to reach a mutually agreeable resolution with SPP over its costs to supply the RTO with emergency energy during the storm. However, it said AECI’s latest request did not address a concrete problem, as required by FERC’s criteria for waivers.

The cooperative said its latest request would have given it and SPP more time to resolve the ongoing dispute. The commission noted that SPP said the payment dispute remains unchanged and that the grid operator’s view was that no progress can be made.

Wind Farm’s Appeals Denied

FERC last week also rejected Salt Creek Solar’s request for a waiver requiring SPP to reinstate the company’s interconnection queue position and dismissed a complaint alleging the grid operator violated the Federal Power Act (FPA) and its tariff by requiring Salt Creek to post an excessive amount of financial security to maintain its queue position (ER21-2878, EL22-11).

Salt Creek said it submitted an interconnection request in 2017 for a 228-MW solar generating facility in Nebraska. It said it didn’t hear back from SPP until October 2020 — when it was allocated $146 million in network upgrade costs — after the RTO cleared its queue backlog. Salt Creek said a modeling error reduced that amount to $54 million, but it was revised again to $184 million when SPP published its second phase results.

The developer contended that the revised results required Salt Creek to post a $35 million deposit, identical to what it owed after the second phase. It said SPP continued to process higher-queued interconnection requests under its prior processes and that numerous withdrawals occurred. In April 2021, SPP notified interconnection customers that the study cluster would need to be restudied  because of the withdrawals, Salt Creek said.

The grid operator eventually notified the developers that their request was deemed to have been withdrawn because Salt Creek did not pay the deposit within the required time.

FERC found in its Aug. 22 order that Salt Creek’s request for waiver to cure its non-payment after receiving notice of its deemed withdrawal was retroactive and prohibited by filed rate doctrine.

The commission also denied Salt Creek’s complaint that SPP had violated the FPA because the wind farm’s developers did not meet their burden under the act to demonstrate that the RTO had violated its tariff or the FPA.

Commissioner Mark Christie concurred in a separate statement, pointing to FERC’s 2021 order that granted Lookout Solar Park, part of the same cluster with Salt Creek, a waiver to pay its financial security after the restudy’s results were available. He said, “Unsurprisingly, the commission is now faced with having to grant an untenable number of waiver requests or deny the same relief to other customers, like Salt Creek, that may indeed be similarly situated.”

Quoting former Congressman Barney Frank (D-Mass.), Christie said, “The biggest lie in politics is when a politician says, ‘I hate to say I told you so,’ because, as Frank put it, ‘Everybody loves to say it.’”

“I told you so,” Christie concluded.

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FERC Fines CPower $2.5M over ISO-NE Capacity Payments

Demand response aggregator CPower has agreed to pay a $2.5 million penalty after FERC’s enforcement division found the company took capacity payments in violation of ISO-NE rules (IN22-7).

The violations stemmed from the use of ISO-NE’s Price Responsive Demand (PRD) structure, implemented in the Forward Capacity Market in 2018.

Under PRD, an active demand capacity resource (ADCR), made up of one or more demand response resources (DRRs), can obtain a capacity supply obligation (CSO) and receive capacity payments.

Importantly, they’re then also required to submit demand response offers from the associated resources into the region’s day-ahead and real-time markets at levels equal to or greater than their CSO.

Between 2018 and 2019, CPower failed to do so, FERC found.

“The deficiencies between CPower’s CSOs and DROs [demand reduction offers] … grew from a minimum of 5.5 MW in June 2018 to a minimum of 33.2 MW in February 2019,” the enforcement filing says.

The company earned nearly $2.5 million in capacity payments that did not have associated DROs, FERC found. And an “individual within substantial authority personnel at CPower” was aware that some of its resources were offering at levels less than their capacity obligations, FERC said.

FERC’s Office of Enforcement started looking into the discrepancy after a referral from the ISO-NE Independent Market Monitor, according to the agency.

In response to the IMM’s initial inquiry, CPower attributed some of the differences to new demand response assets that “did not materialize.”

But FERC found that CPower had violated the ISO-NE tariff, and the company agreed to pay a civil penalty of $2.54 million and disgorge $2.46 million in earnings.

According to the FERC filing, CPower has hired a senior director of regulatory and government affairs and a senior vice president of regulatory affairs in the last year to improve its compliance program.

CPower confirmed with RTO Insider that it settled with FERC, saying, “While today’s outcome stems from the interpretation of what was at that time a new tariff for which there was no precedent, we appreciate that FERC has confirmed that there was no intentional violation and acknowledged the strength of CPower’s compliance program.”

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Counterflow: Vampire Power

tesla powerwallSteve Huntoon | Steve Huntoon

This ad from the local utility caught my eye. It’s from Delmarva, a subsidiary of Exelon, the largest utility company in the country.[1] The idea is to unplug appliances not in use so as not to use electricity in “standby” aka “sleep” aka “idle” aka “inactive” aka “phantom” aka “always-on” mode. Vampire power.

Who wouldn’t want to learn more? So I went to delmarva.com/peakmd, and from there to the details page, where the first specific tip is: Unplug unused electrical devices when you leave a room. Chargers use energy when left plugged in, even after your device is fully charged.[2]

Chargers? Really?

With a little Googling I came across an amusing article putting this premise to the test with a power meter.[3] Each charger registered 0 watts. Adding various chargers to a power strip didn’t register more than 0 watts until the 6th charger. The reading with 6 chargers? 0.3 watts. As the article points out, that’s 2.6 kWh/year which at 13 cents/kKh is 34 cents a year. About 6 cents a charger a year.

Not to scoff at saving 6 cents a year from unplugging/plugging a charger every day for a year. But perhaps there are bigger vampires to slay.

OK, What Bigger Vampires to Slay?

It’s said a zillion times on the internet that the Department of Energy reports that homeowners can save anywhere between $100 and $200 each year by unplugging devices not in use.[4] I can’t find this DOE report (if you can please send me the link).[5]

It’s possible that this range attributed to DOE might have its origin in a Natural Resources Defense Council study, which estimated average residential vampire power costs at $165 per year.[6]

The study put power meters on individual electronic devices at a sample 10 homes in California. When you look at the details (Appendix C), you find that the big usages in “inactive” devices are for things like fishpond/aquarium pumps, refrigerators, furnaces, hot water recirculation pumps,[7] GFCI outlets, networking equipment (modems, routers), printers, alarm clocks, irrigation systems, garage door openers and security systems. In other words, not stuff you unplug (assuming you even could). By the way, there were an average of 65 devices per household using vampire power, so one can imagine the hassle of plugging/unplugging these devices on a daily or other routine basis (again, assuming you would or could).

One of the few things you might unplug when not using is set-top boxes. (TVs themselves consume very little power in stand-by mode.)[8] Is someone going to make a habit of unplugging set-top boxes? Waiting for a reboot every time it’s plugged back in? Missing a show you wanted to record because you forgot to plug it back in? I think not.  

In short: Big savings from unplugging vampire power are as much a fantasy as, well, vampires.[9]

Meanwhile Back at the Ranch

Missing from the Delmarva list is an easy way to significantly reduce electric usage: LED lighting. The math is something like 1,105 kwh/year for average residential lighting,[10] times 13 cents/kwh, times 84% for the reduction in electric usage from switching from incandescent to LED lighting, for about $120 per household. While LED lighting has dramatically increased since 2015, it’s dominant in only half of U.S. households, so there’s a long way to go.[11]

And LED lighting pays for itself in equipment savings alone (ignoring the electric bill savings) because it outlasts an equivalent incandescent by maybe 20 times while costing maybe two times as much.

Wrapping Up

There is reason to doubt the value proposition for customers to fund public service advertising by utilities. But where it happens, the least to ask is that utilities promote effectual and hassle-free ways to reduce electric usage instead of ineffectual and hassle-ladened ways.

[5] I emailed the DOE/Berkeley Lab expert on standby power but didn’t get a reply.

[7] It appears these generally come with sensors and/or timers that reduce electric use. https://homeinspectorsecrets.com/hot-water-recirculating-pumps/how-recirculating-pumps-work/

[9] I’m not suggesting that makers of electronic devices shouldn’t reduce vampire power. There’s been progress on that front from voluntary and mandatory standards, and it should continue.

[10] https://www.eia.gov/consumption/residential/data/2015/c&e/pdf/ce5.3a.pdf (data is for 2015, before large penetration of LED lighting).

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ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal

In a new statement released Monday, ISO-NE and many of its gas and electric distributors warned that the region’s near-term grid reliability depends on its access to LNG — and that access to LNG in turn relies on a single facility outside Boston.

The message comes ahead of a summit next week that will bring FERC commissioners and staff to Vermont to discuss the tenuous state of the region’s grid this winter and in the coming years.

The statement published by the RTO says that  weaning New England off its dependence on imported LNG remains its long-term goal, as the region transitions to more renewable generation.

But in the short term, an LNG import facility operated by Constellation Energy in Everett, Mass., is vital to keeping the lights on, it says.

“The region must ensure the continued operation of the Everett LNG Facility to maintain reliable electric and natural gas service for New England consumers,” ISO-NE and the distributors said.

Everett can store the equivalent of 3.4 Bcf of natural gas and has the equipment needed to import, store, transport and re-gasify LNG. It can deliver up to 435 MMcfd to two of the five pipelines used by generators and gas utilities in New England.

The fate of the Everett facility is tied to the attached Mystic Generating Station, which ISO-NE has paid to retain until its retirement in 2024.

In a separate news release, ISO-NE CEO Gordon van Welie called energy adequacy “under-appreciated, poorly understood, but vitally important.”

“By raising awareness of this issue ahead of the upcoming forum, ISO New England and the region’s utilities hope to begin the process of developing a strong, coordinated response with the New England states, NEPOOL and regional stakeholders to assure that energy adequacy is consciously addressed as the region charts a course toward a clean power system,” van Welie said.

The utilities joining ISO-NE in issuing the statement were Avangrid, Eversource Energy, Liberty Utilities, National Grid, Rhode Island Energy and Vermont Electric Co.

Kickstarting Solutions

The aim of the forum next week is to start hashing out solutions to New England’s unique but well documented challenges around gas supply. Aiming to kick off the conversation, ISO-NE put forward a few ideas in its statement Monday.

For one, the grid operator called on the region to “undertake a comprehensive study of both the energy adequacy problem and the potential solutions for addressing the problem.”

ISO-NE shouldered its own responsibility and acknowledged that any changes to its tariff will have to go through NEPOOL and FERC, but it also called on the states to hold up their end of the bargain.

“The New England states have a major role in determining the nature and extent of any regional risk mitigation solution, since they represent the end consumers who will have to pay for the insurance, and further, control the siting and permitting of the necessary infrastructure,” the statement says.

The RTO also put new weight behind the idea of an energy reserve, which was raised recently by the New England states in a request to the Biden administration. (See New England Governors Ask Feds for Help with Winter Reliability.)

“An energy reserve would cover unusual events, including combinations of major contingencies or extreme weather or both,” ISO-NE said, likening it to regionwide insurance.

The grid operator said a reserve could come in a few different forms: state-regulated cost-of-service infrastructure investments coupled with contracting for the energy; FERC-regulated cost-of-service rates for recovering infrastructure investments and forward energy supply chain arrangements; or FERC-regulated wholesale electric market tariffs to incentivize investment.

“At this stage, given the region’s experience over the past two decades, the region needs to determine how much insurance to buy and which options, or combinations of options, will be the most effective and efficient,” the grid operator said.

All in the Same Room

The forum next week — an all-day affair in Burlington, Vt., on Thursday — will feature nearly 30 panelists from the states, FERC, ISO-NE, distribution and pipelines companies, and more.

According to FERC, it’s intended to “achieve greater consensus or agreement among stakeholders in defining the electric and natural gas system challenges in New England and identify what, if any, steps are needed to better understand those challenges before identifying solutions.”

ISO-NE and the states, in particular, have been lobbing barbs back and forth for years over who holds responsibility for solving the problems facing the region.

Even in the unlikely event of a breakthrough or consensus on Thursday, it’s likely too late to make changes that could help steady the grid this winter: ISO-NE has already said it won’t take steps to stockpile fuel, and that rolling blackouts could be on the horizon if the region sees an extended period of extreme cold. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)

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NJ BPU Denies Deadline Extensions for Solar Project Incentives

New Jersey’s Board of Public Utilities (BPU) earlier this month denied requests by 15 solar developers seeking to extend the completion deadlines for 37 projects.

While the board at its regular meeting Aug. 17 also granted extensions for hundreds of other projects, members expressed reluctance over the denials, as the state faces its own deadline crunch on its renewable energy goals and developers face financial uncertainty and supply chain challenges.

The series of decisions affect participants in the state’s temporary Transition Incentive (TI) program. Now closed to new projects, it provided incentives of between $91.20 and $152/MWh. Projects that aren’t finished by the deadline — initially a year from the project approval — and do not receive an extension would lose the incentive and have to apply to the less lucrative program that succeeded TI.

The BPU said the 15 developers had failed to show sufficient evidence that delays to their projects’ construction were caused by events beyond their control. At the same time, it approved a six-month deadline extension for hundreds of public entities, including schools, universities and municipalities. And the board granted a deadline extension of up to a year for 30 projects planned on a landfill, brownfield or area of historic fill.

The board also approved a six-month extension for four projects approved for TI benefits as part of the state’s community solar program, but it denied an extension to five other projects in the program, saying they were too far from completion.

Providing Certainty

Outlining the decisions at the meeting, Scott Hunter, manager of the BPU’s Office of Clean Energy, said they were aimed at “providing clarity, certainty and support” for solar projects while limiting the cost to ratepayers of extending the deadline and allowing projects that miss their deadline to remain in a higher incentive program.

BPU President Joseph Fiordaliso told the board that the votes demonstrate “the desire of this board to work with the solar industry” while reducing the burden on ratepayers.

The BPU created the TI program to help reshape the state’s incentive programs away from the Solar Renewable Energy Certificate (SREC) Program, which dispensed incentives of about $250/MWh for more than a decade until it closed in April 2020. With incentives about half the size of the SRECs, TI followed in May 2020 but was closed soon after the BPU in July 2022 approved the permanent Successor Solar Incentive Program, with incentives between $70 and $100/MWh.

The shift stemmed from a 2018 state law that directed the BPU to close the SREC program once it reached 5.1% of the power sold. That happened  on April 30, 2020. (See Solar Subsidy Program Ending in New Jersey.)

BPU data for the first half of 2022 show the state is on track to meet a 2025 goal of 5.2 GW of capacity set out in the state Energy Master Plan but needs a dramatic increase in annual capacity installed to meet goals of 12.2 GW in 2030 and 17.2 GW in 2035. (See NJ Faces Challenges as Solar Sector Hits 4 GW.)

Mixed Bag

Fiordaliso said that the state has cultivated and supported the solar industry for 20 years, and the decision to grant only certain extensions reflected that strategy of reducing financial support.

“The industry knew that eventually they were going to get closer to standing on their own two feet,” he said. “We did nothing in secret. We did it in conjunction with the stakeholders. And I think the state of New Jersey has thrived. I think the developers have thrived. And if we continue to work together, we will continue to maintain the solar industry as a major industry here in the state of New Jersey.”

The board voted 4-0 on the extensions, with one abstention. Commissioner Zenon Christodoulou, who joined the board on Aug. 15, didn’t vote in the meeting because he felt that he needed more time to study the issues.

Commissioner Bob Gordon said that any government support for an industry “needs to balance the goals of advancing the new industry against the cost impact.”

“At some point, you need to cut back on those incentives,” he said. “When that industry grows up, if you don’t do that, the risk is the ratepayers subsidize inefficiency. And that’s not what we want to do.”

Scott Elias, manager of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), called the board’s votes a “mixed bag for the industry.”

“It is our opinion that an orderly transition from the Transition Incentive program to Solar Successor Incentive Program ought to recognize that industry is not immune to COVID-19 or global economic trends that leave customers navigating a supply chain riddled with bottlenecks and delays,” he said.

“It’s great that the BPU made limited extensions for some community solar projects and projects serving public entities,” he said. “But markets cannot efficiently operate when power purchase agreements need to be retroactively renegotiated because projects literally can’t be built, interconnected and operating in a narrow 12-month timeline due to unavoidable delays caused by the COVID-19 pandemic.”

Elias also said the extensions for the 30 brownfield projects “will not address the PJM interconnection delays associated with every [brownfield] project that followed the rules and applied before the closure of the TI program in August of 2021.”

“Put simply, the order insufficiently addresses all of the concerns that led to the introduction and passage of A4089,” a bill that would automatically extend the completion date for brownfield solar projects that cannot be completed because of interconnection problems caused by PJM or a utility. The General Assembly passed it unanimously in June, but the Senate has not acted on it. Another trade group, NJ Utility Scale Solar, has backed the legislation and called for a “blanket” deadline extension for TI projects.

Deadline Extension Guidelines

BPU officials gave varying reasons for the extension denials or approvals.

The rejected 37 projects were “not mature enough to meet TI deadlines,” the BPU said in its order. The projects all filed their application shortly before the TI program was closed and cited supply chain difficulties as preventing completion. But developers “knew, or should have known, that they were not going to be able to complete their projects within the time frames enumerated in the TI rules,” the BPU said.

The board noted that in June, it granted a request by ESNJ-Key-Gibbstown to extend the deadline on a 1.38-MW carport solar project in Gibbstown. The board had already granted the project two deadline extensions, and the developer — faced with an April 30 deadline by which to show project completion — sought an additional extension of three months.

The developer argued that it had completed the project but could not interconnect it because Atlantic City Electric had not performed the necessary transmission upgrades.

In granting Gibbstown the extension, the BPU laid out general guidelines on when it would be appropriate to override TI project rules. One of them requires the project to show that the project was electrically and mechanical complete before the deadline expired and had received the necessary final inspections. They also require that the developer show that the utility had committed in advance to completing any upgrades needed to interconnect the project by the deadline but, “despite the developer’s best efforts, the estimated upgrade completion date was unilaterally extended by the” utility.

The 37 projects denied an extension did not demonstrate those conditions, the BPU said.

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FERC Approves Changes to ISO-NE DER Interconnection Process

FERC last week accepted ISO-NE’s proposed changes to its process for interconnecting distributed energy resources, finding them just and reasonable with some clarifications (ER22-2226).

Previously, some DERs had used the ISO-NE interconnection process, while others used state interconnection processes, a disconnect that the grid operator said “results in multiple coordination problems and inefficiencies that in some cases result in adverse outcomes for DER developers.”

ISO-NE proposed that all new DERs proceed through the applicable state processes to ease the uncertainty. (See ISO-NE Sends New DER Interconnection Proposal to FERC.)

In an order on Friday, FERC agreed that the change makes sense.

“We find that ISO-NE’s proposal to exclude DERs from its interconnection procedures is just and reasonable because it would promote certainty in ISO-NE’s interconnection process and reduce a significant burden on ISO-NE,” the commission wrote.

FERC also clarified that “the commission’s jurisdiction over wholesale sales from DERs and their participation in the wholesale markets are not impacted by the change.”

The Solar Energy Industries Association, Advanced Energy Economy and ENGIE North America had all backed the changes, saying they would help resolve unique concerns in New England because of the growth of DERs in the region.

After FERC’s approval, the tariff changes went into effect Sunday.

ISO-NE’s proposal concerned individual DERs; as such, it is separate from its compliance with FERC Order 2222, which deals with DER aggregations. In concluding its order, the commission noted that, as it had in Order 2222, it “may revisit this independent entity variation in the future should [it] discover abuses of the distribution interconnection process or the rise of unnecessary barriers to the participation of distributed energy resources in RTO/ISO markets.”