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November 5, 2024

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Oregon RA Rules Could Favor WRAP Participation

Oregon regulators are moving closer to adopting resource adequacy rules that would incentivize load-serving entities to join the Western Power Pool’s WRAP. 

But during an Oregon Public Utility Commission rulemaking hearing Jan. 11, stakeholders continued to debate transmission forward-showing requirements and the need to allow a capacity backstop charge. 

OPUC filed the proposed resource adequacy rules in September, following an informal process that began in December 2020. 

OPUC staff contend that “resource adequacy concerns are best addressed through regional coordination,” Curtis Dlouhy, senior economist and policy analyst with the agency, said during the hearing. In particular, Western Power Pool (WPP) offers the Western Resource Adequacy Program (WRAP), the West’s first regional reliability planning and compliance program.  

FERC approved the WRAP tariff in February. (See FERC Approves Western Resource Adequacy Program.) 

OPUC’s proposed rule would incentivize WRAP participation by including more stringent resource adequacy planning for those not involved with WRAP, Dlouhy said. 

OPUC-regulated entities that are not WRAP participants would face a two-year forward-showing requirement for resource adequacy. In contrast, WRAP participants must submit resource adequacy forward showings seven months ahead of a season. WPP then evaluates the submission to ensure the participant is meeting its share of the WRAP planning reserve margin. 

“Entities not attached to a regional program have a greater resource adequacy risk and thus should be subject to uniformly stricter requirements,” Dlouhy said. 

“Staff also believes that requirements consistent with WRAP, albeit stricter, provide a clear incentive to join WRAP and thus benefit from a diverse set of energy producers that are involved in WRAP,” he added. 

Capacity Backstop Discussed

The proposed resource adequacy rules would apply to two types of load-serving entities: investor-owned utilities and electric service suppliers (ESSs). Oregon’s Direct Access program allows nonresidential consumers to buy electricity from an OPUC-certified ESS. 

In written comments, the Northwest & Intermountain Power Producers Coalition (NIPPC) said the commission should give ESSs the option to meet their resource adequacy obligations through a capacity backstop charge. Under that option, direct access customers would pay an RA charge to the utility. 

In addition, NIPPC wrote, WRAP’s firm transmission requirement is “very problematic” and shouldn’t be mandatory. NIPPC represents competitive electricity market participants, including ESSs. 

During the hearing, Greg Adams, representing Calpine Energy Solutions, said that WRAP “requires a real shift in regional transmission practices toward advanced procurement of firm transmission.” 

That’s an issue, Adams said, because of Bonneville Power Administration’s current practice of releasing substantial transmission for purchase less than seven months ahead of delivery. 

“There is significant concern with the ability of all load-responsible entities to meet the WRAP’s forward-showing transmission requirement, given the general … inability to obtain incremental, firm, point-to-point Bonneville Power Administration transmission in the forward-showing timeline — seven months in advance of the time of delivery,” Adams said. 

‘Equal Playing Field’

But Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), noted that under FERC’s open access policy, “all entities are on an equal playing field when it comes to acquiring transmission rights.” She said it was unclear what was preventing direct-access LSEs from procuring long-term, firm transmission. 

“We do recognize that procuring long-term, firm transmission on an annual basis … can be more expensive,” Sporborg said. “But we believe that this is a necessary investment to provide really reliable load service.” 

As for the capacity backstop charge, PGE’s Sam Newman said the utility had concerns. 

“We are very uncomfortable with a scenario where the utilities are required to offer a backstop charge, but as a backstop charge there would be considerable flexibility for direct access load to choose or not choose to lean on that charge,” Newman said. “That puts the utilities in a difficult position.” 

Dlouhy with OPUC said there aren’t currently plans to include a capacity backstop charge in the resource adequacy rules, although that could be reevaluated later. He said the rules would be able to function without it. 

“Staff was not confident that significant excess IOU capacity or transmission existed at the moment,” Dlouhy said. 

The proposed rules also include information filing requirements. Oregon’s IOUs would be required to include a resource adequacy assessment covering at least four years in their integrated resource plans. Electric service suppliers would add the RA information to their emissions planning reports. 

Written comments on OPUC’s proposed rules are due Jan. 25 at 3 p.m. 

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NY State Reliability Council Executive Committee Briefs: Jan. 12, 2024

Gas Constraints

NYISO briefed the New York State Reliability Council Executive Committee (NYSRC EC) on an upcoming white paper to propose updates to the ISO’s resource adequacy modeling, including a recommendation to use a tiered load-based approach to estimate gas availability during the coldest winter days. 

Slated to be released by the end of the first quarter, the white paper comes in response to findings by NYISO’s Market Monitoring Unit, Potomac Economics, which found that eastern New York faces significant gas availability issues during peak cold conditions due to regional pipeline constraints. 

Con Edison’s Howard Kosel, the new chair of the NYSRC’s Installed Capacity Subcommittee (ICS), told the EC that NYISO is likely to recommend incorporating a tiered methodology based on load levels in its winter RA modeling to determine gas availability. This approach would assume no gas availability at loads exceeding 26,000 MW.  

The recommendation is based on Potomac’s observation that constraints in eastern New York during the coldest peak winter days were not being accurately modeled. Consequently, the ISO’s RA modeling during these periods was undervaluing certain generators and failing to anticipate the necessary level of gas procurement before peak winter days. 

The ICS will track the ISO’s progress and plans to share the white paper’s findings with the EC once published.  

PRR-151

The Reliability Rules Subcommittee (RRS) also briefed the EC about comments received on Proposed Reliability Rule 151 (PRR-151), which includes suggestions for adjustments to attestation requirements and the introduction of exemptions for evolving technologies. 

The NYSRC developed PRR-151 to address gaps in NYISO’s current interconnection criteria for inverter-based resources (IBRs) and establish standardized rules for IBRs larger than 20 MW. The committee endorsed industry comments on PRR-151 late last year. (See NY Reliability Council OKs Interconnection Standards for Large IBRs.) 

AES Clean Energy, Ørsted, GE and Alliance for Clean Energy New York submitted comments, aiming to ensure PRR-151 remains flexible and does not hinder the integration of IBRs in the future. 

Roger Clayton, chair of the RSS, said the plan is to modify PRR-151 based on the comments received, with the expectation that the revised rule will be presented to and approved by the EC at its next meeting in February. 

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Appeals Court Rejects Review of AEP Transmission Rates

The D.C. Circuit Court of Appeals last week rejected four Texas cooperatives’ request to review a 2019 FERC decision over American Electric Power’s (AEP) transmission rates, saying the commission properly interpreted the terms of AEP’s tariff (22-1166).

The Jan. 11 order is part of a proceeding that stems from FERC’s approval of a settlement allowing AEP to transition its rates from a historical formula rate to a forward-looking formula rate and remove directly assignable transmission costs related to generation. East Texas Electric Cooperative, Northeast Texas Electric Cooperative and Golden Spread Electric Cooperative agreed to the settlement. Arkansas Electric Cooperative Co. intervened but did not join the settlement or oppose it.

AEP’s 2020 annual update filed with FERC included the true-up calculations to be charged for transmission services provided in 2019. The cooperatives challenged the update and raised several issues that could not be resolved through the preliminary challenge process. The commission rejected several of the asserted error claims and a request for retroactive relief, leading to the cooperatives’ petition for review. (See FERC Partially Grants Challenges to AEP Transmission Rates.)

The cooperatives appealed four rulings in the order: one concerning FERC’s interpretation of the protocols to preclude relief for errors that allegedly occurred in prior rate years and three arguments that took issue with the inclusion of certain cost inputs in the 2019 charged rate.

The appeals court agreed with FERC that refunds for errors made in previous rate years are barred under its governing protocols and that the protocols are controlling. It rejected the cooperatives’ other three arguments, saying FERC’s order is reasonable and “adequately explained.”

“We are ‘particularly deferential to the commission’s expertise’ in making highly technical rate classifications,” Circuit Judge Florence Pan wrote.

Pan was one of three judges who heard former President Donald Trump’s immunity claims from criminal charges Jan. 9.

FERC Approves SPP Revisions

FERC on Jan. 11 accepted SPP’s tariff revisions that clarify the RTO’s multiday reliability assessment (MDRA) process, how the day-ahead market consumes commitments made through the process, and how those commitments are compensated through settlements (ER23-2927).

The commission said SPP’s proposal gives it flexibility in addressing system needs through the MDRA process ahead of extreme weather events and helps incentivize resources to perform when the grid faces reliability risks. FERC said the revisions help resources committed during the MDRA process manage fuel price volatility during extreme weather events.

The MDRA process is SPP’s only way to commit resources in advance of its day-ahead market. It studies systems to help determine whether to commit resources and to provide notice to resources that they be online and should procure fuel. SPP said the revisions do not fundamentally change the process’ core concepts.

The RTO said its proposal was informed by its experiences during the 2021 and 2022 winter storms, when it was forced to import capacity from neighbors to meet demand.

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FERC’s Clements Gets GETs’ Benefits to Grid

AUSTIN, Texas — FERC Commissioner Allison Clements is no rock star, but observing her appearances during a gathering of federal and state regulators last summer, you might be mistaken.

Heads turned as she entered a large conference room with several of her staffers, taking a front-row seat for a National Association of Regulatory Utility Commissioners’ discussion on grid-enhancing technologies (GETs). Attendees whispered and nodded in Clements’ direction. Some regulators approached her. Others gave her space. 

Asked if the attention makes her feel like she’s in the same orbit with Mick Jagger or Bruce Springsteen, Clements breaks into a smile and turns toward one of her staffers. 

“Well, I like to go see rock stars,” she answered, noting she did catch Western swing band Asleep at the Wheel’s performance the night before. 

Her day job does take precedence, however. From the moment she joined FERC in 2020, Clements has focused her energy on GETs, such as sensors, power flow control devices and analytical tools that maximize the existing transmission grid. She has taken a key role in helping FERC establish the appropriate incentive mechanisms for the technologies’ adoption.  

Clements earnestly watched the discussion during the NARUC summit. Offered a chance to comment, she stressed the importance of financial incentives to help utilities roll out GETs and said it’s important to dispel the “myth” that GETs are rife with risks when deployed. 

“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” she said. (See FERC-state Transmission Task Force Examines Barriers to GETs.)

A more relaxed Allison Clements | © RTO Insider LLC

And then there are the economic benefits. 

“As I spoke with providers of grid-enhancing technologies and learned anecdotally the amount of savings that people were getting … as well as the amount of capacity they were freeing up on the system, it was a no-brainer to me,” Clements said. “The light bulb went on and I said, ‘You can’t stand up as an economic regulator on behalf of customers if you don’t try and squeeze the savings out of the existing system that has already been paid for.’ 

“The cost of these investments are so modest relative to alternatives that they’re an excellent complement to the development of the transmission system,” she added. “They can’t replace the need to modernize our system with new transmission, but certainly they’re an important complement to that investment.” 

During FERC’s July monthly meeting, Clements referred to a Grid Strategies report estimating that congestion cost the country about $20.8 billion in 2022, up $14 billion since 2020. She also mentioned a Brattle Group white paper that says using GETs to unlock additional capacity on the grid would save customers $8.3 billion. 

She says GETs are a topic “that was once relegated to small windowless conference rooms full of energy grid geeks,” but are now “front of mind” in big rooms before the nation’s regulators.  

“GETs will be a win for customers, and states are taking notice,” she said in July. Recalling NARUC’s discussion of the technologies, Clements added, “My team and I had fun brainstorming technology that came after some of the early GETs, like the floppy disk and the Walkman. Today, utilities around the world have proven experience and results. 

“I came away with the sense that the regulators, as a group, are open to more systematic deployment of these GETs solutions and I look forward to working with them.”  

Noting that part of an engineer’s job description is to be conservative when it comes to reliability, Clements said it’s incumbent on regulators to align financial incentives to encourage the risks of using GETs. 

“[Regulators] don’t have to attach a synchrophasor to every line, but to start getting comfortable and educating and understanding their benefits and limitations,” she said. 

Clements cited as an example PPL Electric Utilities and PJM using a dynamic line rating (DLR) solution to resolve congestion on two transmission lines. She said they spent $500,000 on one line and avoided a $12 million reconductoring. PPL and PJM spent several million dollars on the two lines, which have saved more than $23 million annually, exceeding projections. (See Grid-enhancing Technologies Poised for Growth with Federal Funds.) 

FERC has responded with several initiatives to help facilitate GETs’ deployment. In July, the commission approved Order 1023, which reforms interconnection procedures and included language requiring transmission providers to consider advanced power flow control, transmission switching, and static synchronous compensators and VAR (Volt-Amps reactive) in their studies. 

“It’s a great start for grid-enhancing technologies, or as the rule calls them, alternative transmission technologies,” Clements said during FERC’s July meeting. “The rule’s requirement sets only a low bar: ‘evaluation’ of these technologies. I encourage utilities and grid operators to embrace the opportunity this rule provides, learn more about how to grow your consideration and deployment of these grid-enhancing technologies, and share your learning with your neighbors.” 

The commission has opened a DLR inquiry (AD22-5) to examine whether their use would help ensure just and reasonable wholesale rates by improving the accuracy and transparency of line ratings. It also has a proposed rulemaking (RM21-17) that mandates DLRs and advanced power flow control devices be more “fully” considered in regional transmission planning processes. 

“I would love to see all those things get done,” Clements said. “Grid-enhancing technologies happily provide that modest investment cost. The return on investment is a fraction of the time of a traditional infrastructure expenditure. And they’re dynamic, they’re modular, you can move them, you can use them where they work. There’s just a lot of options to make the grid smarter. The numbers are striking. The dollar savings are striking.” 

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ERCOT Appeals for Conservation as Winter Roars in

With demand projections and available capacity changing by the minute as a winter storm rolled into Texas, ERCOT and state officials spent last week assuaging Texans that the grid will remain standing this week.

Speaking to residents who remember well the devastating February 2021 winter storm that killed hundreds and caused billions in damages when the ERCOT system failed, Texas Gov. Greg Abbott said during a press conference Friday, “I know a lot of people are concerned, ‘Is the power going to stay on?’

“We feel very good about the status of the Texas power grid and ERCOT to be able to effectively and successfully ensure that the power is going to be able to stay on throughout the entirety of this episode,” he added.

The National Weather Service has placed much of the state under a winter weather advisory through Monday, warning of “dangerous” temperatures in the 20s as far south as the Gulf Coast. However, unlike three years ago, little snow or ice is expected.

ERCOT CEO Pablo Vegas said Friday he expects renewable energy to perform as normal, given the lack of precipitation statewide. He said there were no expectations of energy emergencies or conservation calls.

“Things can change and if it does change, we’ll continue to communicate openly over the course of this weekend,” Vegas said.

Sunday evening, things changed. ERCOT issued a conservation appeal for Monday morning due to the freezing temperatures, demand and low reserves. The ISO asked Texans to conserve their electric usage between 6 a.m. and 8 a.m., when solar resources start ramping up and temperatures are forecasted to be below 10 degrees Fahrenheit in North Texas.

ERCOT expects conditions to be similarly tight Tuesday morning. As of 7 p.m. Sunday, the grid operator was projecting a record peak of 86.1 GW, with only 83.8 GW of seasonal available capacity. However, the forecasted curves have changed frequently in the days leading up to the storm’s arrival.

Demand that high is the norm during the summer, having peaked at 85.5 GW in August. ERCOT set its record winter peak of 74.5 GW during the December 2022 winter storm.

The ISO stressed the conservation appeal does not indicate it is experiencing emergency conditions. It said in a press release staff will “remain vigilant and communicate further if conditions change.”

ERCOT also has asked all state and local government agencies to reduce energy use at their facilities until at least 10 a.m. Monday.

The grid operator previously issued a weather watch that went into effect Sunday and expires Wednesday. It said it made the advance notification because of “forecasted significant weather with higher electrical demand and the potential for lower reserves.”

Vegas has said the grid “is as ready and reliable as it has ever been for the winter season.” Legislation passed since the disastrous 2021 winter storm has strengthened the ISO’s weatherization practices — staff have completed nearly 1,800 facility inspections over the past couple of years — and created new ancillary services that can be brought to bear.

SPP Expects Near-record Demand

SPP said it projects to have sufficient capacity to meet anticipated demand this week, despite minimum temperatures in its 14-state Great Plains footprint similar to those observed during the December 2022 storm.

“We have substantial systems and procedures in place and our staff stands ready to mitigate any risks related to maintaining electric reliability,” Senior Vice President of Operations Bruce Rew said in a statement.

With temperatures that could be 30 to 50 degrees below normal, the RTO was expecting load to be as high as 45 GW on Monday and 46 GW on Tuesday. Its all-time winter peak is 47.2 GW, set during Winter Storm Elliott in 2022.

SPP said high pressure building into the Plains behind the cold-weather system may bring a sharp reduction in wind power generation, elevating the risk of outages. The grid operator on Friday issued a conservative operations advisory for its balancing authority area, effective 4 a.m. CT Sunday through 9 p.m. Tuesday.

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NEPOOL Markets Committee Briefs: Jan. 11, 2024

Analysis Group Presents Final Report on Capacity Market

WESTBOROUGH, Mass. — Adopting prompt and seasonal capacity auctions would provide a range of benefits that would help enable New England’s clean energy transition, Todd Schatzki of Analysis Group told the NEPOOL Markets Committee on Jan. 11.

Schatzki presented the consulting firm’s final report on significant potential changes to ISO-NE’s Forward Capacity Market. While the Forward Capacity Auction is currently held more than three years prior to the annual capacity commitment period (CCP), ISO-NE is considering a transition to holding the auction as close as a few months prior to the CCP, as well as dividing the CCP into distinct seasons.

Responding to stakeholder questions based on a draft report the firm presented in December, Schatzki reiterated Analysis Group’s recommendation to adopt a prompt and seasonal market for the 2028/29 CCP. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)

A prompt format would provide a “technology-neutral platform for competition among resource types,” Schatzki told the MC. This would benefit new clean energy resources with shorter development timelines compared to new gas plants, which the existing forward market was originally designed to accommodate, he said.

Schatzki added that a prompt, seasonal market would also more accurately forecast load growth from electrification and the effects of counterbalancing state policies intended to reduce demand. He also noted that a seasonal format would also increase incentives for resources that provide winter reliability benefits.

A seasonal market “creates price signals for the development of capacity resources to complement the variable output of resources important to states’ decarbonization efforts, such as solar PV and offshore wind,” Schatzki said.

Responding to stakeholder questions about the merit of holding seasonal auctions simultaneously or sequentially each year, Schatzki said sequential auctions could result in a small percentage of resources obtaining only a capacity supply obligation in one season, creating a risk that these resources would struggle to recover their annual costs.

In contrast, holding the auctions simultaneously could enable generators to dictate annual revenue requirements that need to be recovered through one or multiple seasons.

Analysis Group declined to recommend either design. It noted that holding the auctions simultaneously “offers many conceptual advantages, but the auction structure decision requires a thorough and careful assessment.”

The firm made some changes to the methodology of the quantitative analysis for the final report, finding that alternatives to the FCM resulted in lower prices in eight out of nine scenarios, by 8% on average. A prompt and seasonal market showed the most significant price reductions, with payments projected to be 12% lower — equal to more than $200 million annually — relative to the FCM.

ISO-NE is planning to make a recommendation on whether to move to a prompt and seasonal market at the MC’s meeting next month, with a vote by the committee on whether to further delay FCA 19 projected to occur in March.

Resource Capacity Accreditation Impact Analysis

Throughout the three-day MC meeting, NEPOOL discussed several aspects of ISO-NE’s ongoing Resource Capacity Accreditation (RCA) project, which would bring major changes in how the RTO calculates the capacity value of several resource classes.

Dane Schiro of ISO-NE presented the RTO’s updated impact analysis framework, which is intended to “provide quantitative insights into the RCA design.”

The analysis will provide information on how the RCA changes would affect accreditation values and capacity supply obligations for different resource types, as well as metrics related to capacity market prices and loss-of-load expectations. ISO-NE performed an initial version of the impact analysis in April 2023 before a software issue derailed the project for several months.

In a change from the initial impact analysis methodology, gas resources will now be studied at the fleet level instead of at the individual level, while the risk assessment for oil resources will include a two-week inventory limit.

The analysis will use a base case that employs the resource mix associated with the upcoming FCA 18 and the load forecast for FCA 19. Imports will be based on the level cleared in FCA 13, which represents the median amount from the past five auctions.

The first phase of the analysis will focus on resource accreditation in the base case, while the second phase will look at different sensitivity scenarios, including changes to the amount of fossil fuel resources replaced by renewables and an increased winter peak load. The third phase is intended to give quantitative insight on auction results, including demand curves, clearing prices and LOLE.

Marginal Reliability Impact Calculations

As a part of the ongoing RCA project, Steven Otto of ISO-NE detailed the RTO’s proposed approach to calculating the marginal reliability impact (MRI) and qualified MRI capacity (QMRIC) values for different resource classes.

MRI aims to quantify how small changes to a given resource’s output would affect grid reliability. MRI is an input to QMRIC, which represents a resource’s overall accredited capacity.

MRIs will be calculated for two seasonal periods: a June-September summer period and an October-May winter period. Seasonal MRI values for existing thermal resources “will be driven by their equivalent forced outage rate on demand excluding events out of management control,” ISO-NE said.

For new thermal resources, MRI values will be calculated based on the averages associated with their resource class. MRI values for new storage and large wind and solar resources will be created by modeling the marginal addition of a proxy resource. Small existing intermittent resources with a nameplate capacity of less than 10 MW will be combined into aggregations for their MRI assessments.

Gas Accreditation

Prior to the MC meeting, ISO-NE issued a memo detailing several potential methodologies for accounting for gas system constraints in the RCA updates. The current accreditation approach does not account for gas system constraints when determining a resource’s capacity value.

The RTO is recommending a derating approach for gas resources, which “decreases the accredited capacity of all gas resources so that their total accredited capacity equals the gas constraint,” ISO-NE wrote.

ISO-NE also discussed the possibility of a “market constraint approach,” which would not decrease the accreditation of gas resources based on a lack of firm fuel commitments, but instead would “decrease the amount of gas capacity procured in the winter … and would pay that capacity a lower price.”

“The market constraint approach achieves the same level of reliability as current rules, but at least cost,” ISO-NE said. “The awards determined by the market constraint are cost minimizing: No other set of awards could achieve the same level of reliability at lower social costs.”

ISO-NE proposed to conduct additional analysis into implementing a market constraint approach, while adding that the derating approach would be easier to quickly implement and makes sense as a “as a reasonable transition mechanism.”

“Overall, the market constraint approach is preferred but is not implementable for FCA 19 or a one-year delayed auction timeline and likely requires a seasonal market construct,” the RTO wrote.

ISO-NE also included the possibility of an “MRI=0 approach,” which would not award any accredited capacity to gas resources that lack firm fuel arrangements. The RTO wrote that this approach “would not procure a socially optimal quantity of gas capacity, nor would it pay the gas capacity an appropriate price.”

Tom Kaslow, vice president at FirstLight Power Resources, presented to the MC on the company’s concern that ISO-NE’s proposed approach would not provide adequate incentives for firm gas contracts.

Kaslow told RTO Insider that ISO-NE’s proposal to determine the maximum reliability contribution from gas resources based on the expected available gas supply could “undermine the forward contracting for firm gas supply access that would assure that the future year assumed gas supply is realized.”

“While there is a history of a certain level of available gas supply to gas-fired generators, without advance contracting, circumstances can change, as evidenced by the possible retirement of the Everett Marine Terminal,” Kaslow added.

The company is asking ISO-NE and NEPOOL for additional analysis into how the different approaches to accounting for gas system constraints would impact incentives for firm fuel contracts.

Committee Votes

The MC voted to support an update to ISO-NE’s compliance with Order 2222 that would make distributed energy resource aggregations responsible for submitting their own metering data to ISO-NE.

FERC clarified in October that this metering information could “come from or flow through distribution utilities.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.) ISO-NE’s current proposal would allow a DERA “to designate itself, a party acting on its behalf or the host participant to be the assigned meter reader.”

The committee also voted to recommend updating the forward reserve offer cap to $7,200/MW-month and delay the publication of forward reserve auction offer data for 12 months to address market power concerns.

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NJ Grid-scale Solar Projects Face BPU Scrutiny

The New Jersey Board of Public Utilities rejected one project and supported another in the state’s new grid-scale solar program Jan. 10. In a separate move, the board agreed on a consultant to prepare the groundwork for its fourth offshore wind solicitation, expected to begin early this year.  

The two solar cases were seeking approval under the Competitive Solicitation Incentive (CSI) program, which the BPU launched last year. Despite the agency’s hopes it eventually will be a major part of the state’s solar sector, it has yet to endorse any CSI projects.  

The BPU in spring 2023 opened the first solicitation under the CSI program, which handles projects greater than 5 MW. But the agency in July rejected all of the applications, saying the bids were too high. The agency is accepting applications under a second solicitation, which opened Nov. 27 and closes Feb. 29. (See NJ Rejects Solar Bids as Too Expensive.) 

In each of the two proposals discussed Wednesday, the developer is seeking to build a solar farm on land that is preserved under New Jersey law, and so usually is off-limits to solar projects. The developers asked the BPU to grant waivers that would allow the projects to move ahead. 

The board rejected the waiver request by Nexamp Solar, which is seeking to build a 10-MW floating solar project on two islands, each 10 acres in size, on the Wanaque Reservoir. The reservoir is in the Highlands Preservation Area, which is part of the Appalachians and stretches about 60 miles through New Jersey and provides a large chunk of the state with drinking water. 

Commissioner Zenon Christodoulou, speaking after the vote, said it was a “difficult” decision. 

“What we’re trying to do is try and get as much renewable energy out there,” he said. But the developer had not met the CSI rules, he explained, and urged other developers to “please be a little bit more precise with their filings and [be] on time,” in their submissions. 

Open Space or Built Land

CSI rules allow a waiver if the project is sited on a “built environment,” rather than pristine land. The developer argued that the reservoir fit the description because the project won’t be built on open space, but a water body. In addition, the developer argued that the CSI rules favor solar developments on “previously existing impervious surfaces,” and the reservoir fit that description because it was built in the 1920s with a floor on a “bedrock resistant to filtration,” according to the board order.

BPU staff said that to receive a waiver, any applicant had to meet several criteria under CSI rules, including showing the project is in the public interest, which Nexamp Solar did. But during the two- to three-year application process the project failed to provide sufficient information to the state Highlands Council and New Jersey Department of Environmental Protection (DEP) when asked, said Laura Scatena-Amissah, a BPU research scientist. 

“This failure to address the specific concerns of the relevant administrative agencies outweighs general statements about environmental or community benefits,” she said. 

In the second case, the board approved a waiver request by NextGrid Inc., which is seeking to build a 5.2-MW solar farm and battery storage facility under the CSI program in Manchester Township on 18.4 acres of a former landfill. The project would be sited in the Pinelands Management Area, a 295,000-acre area of forest and wilderness in South Jersey. 

Although the Pinelands Comprehensive Management Plan allows solar projects in that area only in “very limited circumstances,” the developer’s interaction with state agencies — including the Pinelands Commission, which oversees the area — suggested the waiver should be granted, according to the BPU order. 

Aside from the economic benefits to the area and the generation of renewable energy, the project would help cap and close the landfill and would help an overburdened community, BPU staff said. The project also has the support of the DEP and Pinelands Commission, and so a waiver is warranted, the order said. 

Fourth OSW Solicitation Work

In a separate move, the BPU agreed to extend the contract of a consultant working on the state’s third OSW solicitation, in part so the same company could start work on the state’s fourth search for OSW project proposals. 

Although the BPU is evaluating four proposals submitted in the third OSW solicitation, Gov. Phil Murphy (D) on Nov. 29 said the agency should prepare to launch a fourth solicitation early this year. 

His statement followed the announcement by Danish developer Ørsted on Nov. 1 that it would abandon the state’s first OSW project, the 1,100-MW Ocean Wind 1, and a second project in the state, the 1,148-MW Ocean Wind 2, because the developer no longer believed they were financially viable. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) The decision puts back by at least two years the date by which the state expects to have an OSW project up and running. 

Murphy, in a release announcing his acceleration of the program, said he did so in “recognition of the strong future of New Jersey’s offshore wind industry. 

“New Jersey can — and will — continue to remain a burgeoning offshore wind development hub that attracts new projects and their accompanying economic and environmental benefits for generations to come,” he said. 

The BPU is evaluating four proposals submitted in the third OSW solicitation and is expected to announce in the first quarter which — if any — proposals are selected for development. The solicitation is expected to award capacity up to 4 GW or more, with a completion date of between 2027 and 2029. 

The BPU OSW schedule calls for the fourth solicitation to begin in the first quarter of this year, with projects awarded a year later and completed by 2032. The schedule sets a preliminary capacity award of 1.2 GW in the solicitation. 

Consultant Levitan & Associates Inc. (LAI), of Boston, is working for the BPU on the third solicitation, work that includes evaluating the four applicants, BPU staffer Kira Lawrence told the board. She said the agency needs to extend the consultant’s contract to do further work on the third and fourth solicitations. 

“In order for staff to comply with the governor’s direction, the consultant is needed to begin work as soon as possible,” she said. LAI has been the board’s consultant for all three previous solicitations and has experience with providing the necessary services and knowledge of the board’s processes, she added.

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DOT to Fund EV Chargers in Remote, Disadvantaged Communities

The Department of Transportation has rolled out the first round of funding for EV chargers to be located in remote, tribal and low- and moderate-income communities across the nation, with $623 million from the Infrastructure Investment and Jobs Act going to 47 projects in 22 states and Puerto Rico, according to a Jan. 11 announcement.

The funding will put a total of 7,500 EV chargers in a range of locations, from multifamily housing developments in New Jersey and Maryland to public libraries in California to remote villages like Haines, Alaska (2023 population: 1,951), which currently has no chargers.

The North Central Texas Council of Governments will get $70 million for up to five hydrogen fueling stations for medium- and heavy-duty freight trucks at sites in Dallas-Fort Worth, Houston, Austin and San Antonio, according to the announcement.

The awards are the first being made from the Charging and Fueling Infrastructure (CFI) Discretionary Grant Program, which received $2.5 billion from the Infrastructure Investment and Jobs Act. The program is the competitive counterpart of the IIJA’s $5 billion National Electric Vehicle Infrastructure (NEVI) program, which provides all states with yearly, formula-based allocations to put EV chargers on major interstate and state highways.

The first NEVI chargers went into operation in Ohio and New York at the end of 2023.

CFI is aimed at filling in the gaps at the local level, working with organizations that might not qualify for NEVI or other funding, in line with President Joe Biden’s Justice40 initiative, which is intended to ensure that 40% of the benefits of all federal funding go to disadvantaged communities.

According to DOT, more than 70% of the projects receiving funds will be in disadvantaged communities. The projects also must comply with DOT’s technical standards for federally funded chargers, which require that all charging stations have at least four ports and that direct current fast chargers be at least 150 kWh. Public chargers must be available 24/7 and accept all major credit or debit cards.

“From my time working at the local level, I know that finding electric vehicle charging in a community is different from finding charging along highways,” Deputy Secretary of Transportation Polly Trottenberg said in the announcement. The CFI-funded projects “will provide Americans with convenient, straightforward charging options in their communities.”

Energy Secretary Jennifer Granholm hailed the awards as “bringing an accessible, made-in-America charging network into thousands of communities while cutting the carbon pollution that is driving the climate crisis.”

“Every community across the nation deserves access to convenient and reliable clean transportation,” she said.

Expanding the U.S. charging network is widely seen as critical for building consumer confidence in and sales of EVs. The DOT estimates more than 4 million electric cars, SUVs and pickup trucks are on the road in the U.S., while the number of charging points has grown 70% since Biden took office. Private investments in the EV and charger supply chain have grown by more than $155 billion, according to administration figures.

The DOT has yet to announce when it will open applications for the next round of CFI funding.

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NERC Urges Preparedness Ahead of Weekend Storms

NERC is urging electric stakeholders to take preparations ahead of a winter storm system that the National Weather Service expects to “hammer much of the eastern half of the” U.S. this weekend and next week. 

In a statement earlier this week, the ERO said the coming weather “has the potential to create significant challenges, especially in major metropolitan areas.” Predictions by the NWS include blizzard conditions with 6-12 inches of snow from eastern Nebraska to central Michigan, and potentially more than a foot of snow in northern lower Michigan.  

Much of Montana and North Dakota is expected to see temperatures fall below zero degrees Fahrenheit Jan. 12, with single-digit temperatures likely in the Central Plains, Iowa and Minnesota. These conditions will likely persist “well beyond the end of the week,” the NWS said. 

Additionally, high winds are expected in the Deep South and Southeast U.S. with the possibility of tornadoes. While rainfall totals are expected to be relatively light compared to earlier this week, parts of the Mid-Atlantic and Northeast, already saturated by heavy rain, may experience floods. NWS is also forecasting “unsettled weather conditions” in the West, with the Oregon Cascades, along with the coasts of Oregon and northwestern California, predicted to receive several feet of snow. 

In a video posted Tuesday, NERC CEO Jim Robb said that “while forecasts do not indicate that this polar air mass will dip as far south as it did during Winter Storm Uri in 2021, the concerning pattern shows a much colder and broader area of impact.” He asked industry to “take this upcoming weather system extremely seriously and be prepared for extreme temperatures and wind chills.” 

NERC said stakeholders will need to pay “prudent attention throughout the long holiday weekend” to winterization and fuel supplies. The ERO encouraged generator owners and operators, reliability coordinators, balancing authorities, transmission operators and fuel suppliers to evaluate energy adequacy, and load-serving entities to “review their demand projections to ensure the highest levels of reliability.” 

NERC’s release mentioned the ERO’s “comprehensive approach” to preparing for and mitigating the impacts of severe weather events, including the new cold weather standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) approved by FERC last February. (See FERC Orders New Reliability Standards in Response to Uri.) 

Work on additional cold weather standards continues at NERC: The organization’s Board of Trustees voted in October to send EOP-011-4 and TOP-002-5 (Operations planning) to FERC for approval. NERC’s board also warned last month that it is prepared to unilaterally approve the proposed standard EOP-012-2 — which FERC ordered the ERO to submit for approval by February 2024 — if it fails its next ballot round this month. (See NERC Board May Force Action on Cold Weather Standard.) 

NERC warned in its 2023 Winter Reliability Assessment that much of North America faces elevated or high risk of energy shortfalls during extreme weather conditions this winter. A common theme in multiple regions was that generation has not kept pace with demand growth, with the added concern in New England that using natural gas for both home heating and electric generation could place unsustainable burdens on the gas delivery infrastructure. (See NERC: Grid Risks Widespread in Winter Months.) 

This week’s statement also mentioned NERC’s 2023 Long-Term Reliability Assessment, which advised that “integrated planning and effective coordination [are] imperative” in light of the growing interdependence between North America’s gas infrastructure and electric grid and the risks posed to both systems by extreme cold temperatures. 

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Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP

MISO stakeholders this week pushed MISO to publish sooner rather than later a new deadline for accepting aggregators of distributed resources into its markets.

MISO hopes to file for a new implementation date and clear up other aspects of its Order 2222 compliance with FERC by May 10. While the RTO plans to discuss several aspects of its revamped compliance multiple times between now and early spring, it plans to devote only one final April 11 meeting of its DER Task Force to discussing the new target date. After that, it will present a final, reworked Order 2222 compliance proposal to the MISO Market Subcommittee at its April 18 meeting.

In October, FERC told MISO it had to achieve a more timely Order 2222 compliance, striking down the RTO’s originally proposed plan to accept aggregators’ offers beginning in the first quarter of 2030. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

Clean Grid Alliance’s Rhonda Peters asked MISO not to wait to hold discussions on its new implementation until spring.

“The implementation date is a topic of great importance to many stakeholders,” she said during a Jan. 11 teleconference of MISO’s DER Task Force.

MISO’s Marc Keyser said landing on a new implementation date will be relatively “straightforward” when compared to the other outstanding Order 2222 compliance directives FERC ordered MISO to resolve.

“Multinodal aggregations are a pretty complex topic…we think we’ll need multiple discussions there,” Keyser said.

However, Sierra Club’s Justin Vickers said the implementation date is a “big deal.”

“I think not being able to talk about that until the very end will affect how we will discuss other issues,” he said, adding it would be “prudent” for MISO to share its revised go-live date with stakeholders expeditiously.

Organization of MISO States Executive Director Marcus Hawkins said MISO’s 2030 finish date was revealed belatedly in its first round of compliance work, which led OMS to reassess MISO’s compliance plan. OMS last year filed comments with FERC that a 2030 implementation date was too gradual.

Advanced Energy Management Alliance’s DeWayne Todd asked MISO to consider a staged implementation to the order, where it works in DER aggregators’ participation as it’s able.

Otherwise with the Order 2222 compliance edits, MISO is reaching out to its stakeholders for advice on how it should best coordinate with regulators, distribution companies and aggregators to solve FERC’s directive to establish cybersecurity and customer data privacy protections for meter data management.

The RTO also is seeking stakeholder reactions on how it should set up dispute resolution when disagreements arise between aggregators, LSEs, distribution companies and/or regulators over meter data or settlements. MISO is proposing that it become involved and review an aggregator’s participation in its markets when its settlements are successfully disputed more than 10% of the time by an LSE and the financial impacts of successful disputes exceed $7,500 for an individual dispute or average at least $100,000 across all successful disputes.

MISO will hold two workshops with distribution companies on Order 2222 compliance: a Jan. 22 teleconference to discuss a 60-day timeline and process for reliability reviews to monitor DER aggregations’ impact on the distribution system and a Feb. 27 teleconference to hash out operational coordination.

MISO also plans to discuss how it might handle DER aggregations across multiple pricing nodes at DER Task Force meetings beginning in February.