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December 30, 2024

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FERC Rejects PURPA Petition in Arizona Solar Case

FERC has declined to act on a petition that accused Arizona’s Salt River Project of setting rates that discriminate against customers with rooftop solar (EL24-54).

The petitioners had asked FERC to initiate an enforcement action against SRP under the Public Utilities Regulatory Policies Act. But in a notice of intent not to act issued March 21 at its monthly open meeting, FERC declined to do so.

The petition was filed Jan. 12 by two SRP rooftop solar customers, Karen Schedler and Jeremy Helms, and the nonprofit advocacy group Vote Solar. An amended petition filed Jan. 22 added Solar United Neighbors as a petitioner.

The petition alleged SRP’s rate plans discriminate against rooftop solar customers through a higher fixed monthly charge for solar customers and more advantageous peak periods for non-solar customers. (See Petition Seeks PURPA Protections for Rooftop Solar.)

Non-solar customers have a three-hour peak period. The time-of-use plan offered to solar customers has a longer peak period that varies by season: 2 to 8 p.m. in the summer, and 5 to 9 a.m. plus 5 to 9 p.m. during the winter, according to the petition.

But SRP said in a motion to dismiss that its retail rates for rooftop solar customers are just and reasonable “and fully consistent with PURPA’s costing principles.”

SRP, along with intervening parties including the National Association of Regulatory Utility Commissioners, also claimed that the issue of SRP’s retail rates is not within FERC’s jurisdiction.

“Petitioners challenge SRP’s rate design as applied to retail customers with rooftop solar PV panels located behind the meter,” NARUC wrote in a filing. “Such challenges to retail rates are subject to exclusive state jurisdiction.”

NARUC also said the petition offered no evidence the retail customers’ rooftop solar is a “qualifying facility” under PURPA.

PURPA was enacted in 1978 to encourage development of small power producers and co-generators and to reduce fossil fuel demand.

In concurring statements accompanying FERC’s order, Commissioners Allison Clements and Mark Christie expressed differing opinions on the issue of FERC’s jurisdiction.

Christie said he was persuaded by the arguments from SRP, NARUC and other intervenors that the issues in the petition should be addressed at the state rather than federal level.

But Clements said the mere fact that residential rooftop solar customers are making the claim does not make it a state issue.

“While states and relevant non-jurisdictional entities such as SRP have retail rate authority, PURPA provides for federal jurisdiction over a utility or retail authority’s implementation of PURPA’s obligation to purchase from and sell to qualifying facilities,” Clements wrote. “Further, it is clear that behind-the-meter rooftop solar arrays owned or leased by residential customers can be qualifying facilities.”

FERC’s decision means the petitioners may bring an enforcement action against SRP “in the appropriate court,” the commission said.

David Bender, an Earthjustice attorney representing Vote Solar, said he had expected the commission’s decision to not bring an enforcement action. Bender said he was aware of FERC bringing enforcement actions only a couple of times in the 46 years since PURPA was enacted.

“We filed our petition because it is a prerequisite to bringing our own enforcement action in federal court, which we will proceed to now do,” Bender said in an email to RTO Insider.

An SRP spokeswoman said the company was pleased with FERC’s decision, noting the utility’s position was supported by the American Public Power Association and the Large Public Power Coalition, in addition to NARUC.

“SRP offers multiple rooftop solar rate options to customers that are just, reasonable and fair and prevent cost shifts from the class of customers who have chosen to put rooftop solar on their homes to the class of customers without rooftop solar,” the spokesperson said.

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Panel Connects Clean Energy Transition to Boston’s Big Dig

SOMERVILLE, Mass. — Selling the long-term narrative to the public on the significance of clean energy infrastructure is as important as any technical barriers to infrastructure development, a panel of energy experts emphasized at Greentown Labs on March 21.

Convened by Advanced Energy United, the event was aimed at drawing connections between the infrastructure needs of the clean energy transition and Boston’s Big Dig, a massive construction project that replaced an elevated highway cutting through the city’s downtown with an underground tunnel.

Ian Coss, producer of a 2023 podcast by WGBH investigating the history of the massive project, told attendees the Big Dig serves as both “a cautionary tale” and “a point of inspiration” for clean energy infrastructure projects.

Completed in 2007, the idea behind the Big Dig initially was conceived in the early 1970s; it took 20 years to “even get to the starting line of construction, and then it took another 16 years to build it,” Coss said. The project ultimately cost more than $20 billion, was beset by a series of controversies and has long carried the reputation of a boondoggle, he said.

But despite the construction challenges, the completed project now provides significant quality-of-life benefits to the city and the broader region, Coss said. Connecting the project to the daunting need for infrastructure that lies ahead, Coss said the history of the Big Dig shows “how important narrative is to public works.”

“A project can be transformative and at the same time viewed very negatively for a long period of time,” Coss said, adding that the project’s reputation led to a “chilling effect” on major infrastructure projects in the region.

Rebecca Tepper, secretary of Massachusetts’ Executive Office of Energy and Environmental Affairs, said the challenges the state faces today in developing infrastructure may be even greater than those of the Big Dig. While the Big Dig was limited to the city of Boston, the infrastructure needed for the clean energy transition will extend through the Northeast and require intense regional collaboration, she said.

At the same time, Tepper remains optimistic, and she highlighted community engagement and benefits as the key components to the successfully deploying infrastructure at scale.

“Can we still build big things? Yes, because we have to,” Tepper said.

With impending emission target deadlines, states also do not have the luxury of time for developing clean energy infrastructure, the panelists said.

“Time is no friend: It’s no friend in politics, in life and in infrastructure projects,” said Joe Curtatone, president of the Northeast Clean Energy Council.

Other challenges specific to energy include the fact that the existing infrastructure needs to continue functioning throughout the construction process, and there often is limited tangible or visible benefits to celebrate when the infrastructure is completed, said Maria Robinson, director of the U.S. Department of Energy’s Grid Deployment Office.

Accompanying energy infrastructure with projects that provide real benefits to local communities can help “make it more tangible,” Robinson said.

Despite the myriad challenges, one advantage of today is the alignment of federal, state and local governments on the need to quickly develop clean energy infrastructure, and the availability of federal dollars to do so, said Jeremy McDiarmid, managing director of Advanced Energy United. McDiarmid called this alignment “a moment to seize.”

Advanced Energy United recently co-founded the Transmission Possible coalition, which is working “to elevate the conversation” and make transmission issues more accessible to a general audience, McDiarmid said. (See Transmission Coalition to Fight for Expanded Grid.)

“It’s something that everybody needs to understand,” McDiarmid said. “We don’t have another choice; we don’t have the luxury of just ignoring this.”

Ultimately, the success of the clean energy transition will depend on more than the success or failure of any single project, McDiarmid said.

“We need to think bigger,” McDiarmid said, “telling a big-picture story so the unfortunate bumps along the road are just that.”

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3 FERC Nominees Quizzed by Senators in Hearing Short on Fireworks

The three FERC commissioner nominees faced questions from the Senate Energy and Natural Resources Committee on March 21 in a hearing light on fireworks. 

“The job calls for people who can fairly assess the needs and concerns of all interests affected by our energy policies and apply the law,” said committee Chair Joe Manchin (D-W.Va.). “Today we’re here to assess the experience and qualifications of three nominees before us for this important job.” 

The nominees include Judy Chang, who is up for the seat opening in July, FERC staffer David Rosner, who most recently was detailed to Manchin’s committee and Lindsay See, the West Virginia solicitor general.  Rosner and See are nominated for the two open seats on the commission. The committee took just three weeks to hold a nomination hearing after the White House announced choices. (See Biden Names 3 Nominees to Give FERC 5 Members Again.) 

Ranking Member John Barrasso (R-Wyo.) tied Chang — who worked for Massachusetts after being hired by Gov. Charlie Baker (R) — to what he called that state’s “failed policies.” 

“To remind the committee, this is a state that consumes twice as much electricity as it produces,” Barrasso said “It’s a state that benefits from the resolve of other states and other countries to produce the energy that Massachusetts needs and uses. And it’s a state where residents pay among the highest electricity and natural gas prices in the nation.” 

In her role in Massachusetts, Chang advocated against expanding natural gas infrastructure to the region, which Barrasso highlighted in old quotes. 

“As part of the state government, however, I personally experienced what it’s like to go through winters in New England and from the governor all the way down, the nail-biting experiences to make sure that we have not only reliable service, but affordable service,” Chang said. “And that is particularly the time when New England is more like Germany than it was like Pennsylvania in its cost and availability of natural gas.” 

If she had a “magic wand” she said she would like to see more natural gas infrastructure for the region but noted that the issue is very difficult in New England. 

Sen. Mazie Hirono (D-Hawaii) asked Chang how her time as Massachusetts’ undersecretary for Energy & Climate Solutions would inform her time on FERC. Chang responded that reliability must be considered, or the energy transition won’t work. 

“No one in this country will tolerate any outages,” Chang said. “So, I think I understand the complexity of the energy systems through my work in Massachusetts, and I will definitely carry that with me going forward.” 

Hirono also got into a back-and-forth with See over West Virginia v. EPA, a case the nominee argued on behalf of the state before the U.S. Supreme Court. The court relied on the “major questions” doctrine to find EPA overstepped the Clean Power Rule by using the Clean Air Act in a way Congress never intended. More recently, the court has taken up a case that threatens to overturn the Chevron Doctrine, which has courts pay deference to regulatory agencies on technical questions under their jurisdiction. (See: Supreme Court Hears Oral Arguments on Overturning Chevron.) 

Hirono asked how See views FERC’s authority given the recent legal developments and points she made while arguing the case for West Virginia. 

“I certainly understand that [FERC] will be a different role of acting impartially,” See said. “And I think that that will be important when it comes to [the] role of the agency. As I have said, my philosophy would be to follow the law. And I would be looking at experience to see what exactly it is Congress delegated and tasked FERC with doing. I’d be looking for that best interpretation consistent with governing statutes.” 

Getting rid of Chevron would be a “tall order” for Congress because it would have to be very precise in what it delegates to agencies, said Hirono, who asked See whether FERC could consider carbon pollution in its decisions. 

“My understanding is that FERC, like any other agency only has the authority that Congress has delegated to it,” See answered. 

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FERC, State Regulators Renew Collaboration

Nearing completion of its long-awaited transmission planning rulemaking, FERC announced March 21 it’s forming a new working group with state regulators to continue the dialogue it began in 2021. 

In its order, the commission created the Federal and State Current Issues Collaborative, which will provide a venue for discussions on issues including electric reliability and resource adequacy; natural gas-electric coordination; wholesale and retail markets; new technologies and innovations; and infrastructure (AD21-15, AD24-7). 

FERC said the new group will be like the Joint Federal-State Task Force on Electric Transmission, which has held eight meetings since late 2021, the most recent last month. (See Utility Regulators Repeat Concerns About Tx Siting Oversight.) 

“Given the success of this collaboration and the array of additional cross-jurisdictional issues relevant to FERC and state utility commissions, we seek to continue a formal collaboration to explore electricity sector issues where there are relevant jurisdictional nexuses or regulatory gaps,” the order said. 

The task force discussed issues including regional and interregional transmission planning; siting; cost allocation; generator interconnections; physical security; and grid-enhancing technologies — several of which are likely to be addressed in the commission’s transmission planning and cost allocation rulemaking (RM21-17). (See FERC Watchers Weigh in as Transmission Rule Approaches Finish Line.) 

“Yes, we have more work to do on transmission, but we are landing the plane,” FERC Chair Willie Phillips said in a press conference after the commission’s monthly open meeting. “And soon, we’ll need to turn to other matters and issues that I think we can get helpful and valuable feedback on from our state colleagues.” 

Like the task force — which was due to expire in November — the new group will run for three years unless extended and will include the FERC commissioners and 10 state regulators nominated by the National Association of Regulatory Utility Commissioners (NARUC). 

The order requested that NARUC nominate two state representatives from each of NARUC’s five regions.  

“All state commissions may suggest agenda topics for public meetings of the collaborative and may also submit comments before and after on the topics being discussed at such meetings,” FERC said. “In addition, the collaborative may consider convening regional meetings with opportunity for participation by all state commissions in the region.” 

The first meeting of the collaborative is expected in fall 2024. 

Phillips said the task force “addressed almost every issue that I can imagine under the transmission reform regime,” and that the commission included states’ feedback on Order 2023, which revised the pro forma generator interconnection rules to clear queue backlogs (RM22-14). (See FERC Updates Interconnection Queue Process with Order 2023.) 

Now, he said, it’s time for the commission and states to “pivot” to reliability concerns.  

“We heard today from Commissioner [Mark] Christie: there is a concern about reliability [and] resource adequacy. That’s also a priority, and I want to hear from our state colleagues on those issues as well. Because … no commission has taken more action on reliability than this one. Every month since I’ve taken over as chairman, we’ve taken a major action on reliability.” 

NARUC President Julie Fedorchak, a North Dakota regulator, said the states are eager to continue discussions with FERC. “The role of state utility commissioners is increasingly more challenging and consequential to the quality of life, safety and economic health of this nation,” she said. “Ensuring the reliability of the grid as the energy sector evolves at a rapid pace is crucial.”  

North Carolina Commissioner Kim Duffley, who represented the states as the co-chair of the transmission task force, said the group “allowed for meaningful dialogue and assisted in providing a clearer understanding of regional differences.”   

“The states look forward to seeing the beneficial results of our conversations and working with our federal partners on other significant federal-state issues,” she added. 

Michael Brooks contributed to this article. 

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Members Call for More Tx Expansion Following MISO’s $20B LRTP Blueprint

DALLAS — MISO’s conceptual, $20 billion, 765-kV transmission suggestion took top billing at Board Week, with some members asserting that MISO has even more transmission to plan if to meet the future confidently.  

MISO earlier this month said it envisioned a $17 billion to $23 billion second long-range transmission plan (LRTP) portfolio with most lines rated at 765 kV. Many of the proposed line routes in the massive buildout track those approved under the first LRTP for MISO Midwest. (See MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV; MISO Outlines Benefits of New LRTP Investments.)  

“This is the System Planning Committee of the MISO Board of Directors, and I’m going to tell you right off the bat, there’s nothing to see here,” MISO Director Mark Johnson joked when opening the March 19 meeting discussing the RTO’s grid-expansion activities.  

“I can tell you today that we’re starting to glimpse the finish line,” MISO Vice President of System Planning Aubrey Johnson said of the second portfolio. He said MISO personnel have logged more than 25,000 hours to reach the blueprint.  

Aubrey Johnson reminded attendees that MISO has said for years its members are contemplating adding up to $500 billion in new generation to achieve carbon reduction goals and that the RTO could recommend $100 billion in transmission projects to incorporate those resources into the grid over the next two decades.  

“The generation expansion is driving the transmission we plan to marry to it,” he explained.  

By 2042, MISO predicts it likely will manage 466 GW of installed capacity, have a 145-GW peak load that occurs in January rather than July and will have overseen 103 GW in generation retirements. Its fleet will emit 96% less carbon pollution than it did in 2005.  

Senior Vice President of Planning and Operations Jennifer Curran said while MISO can’t pin down precisely what the future’s fleet resembles, the second portfolio is MISO’s “least-regrets” plan.  

MISO Director Nancy Lange said MISO’s plan appears necessary to usher in the future resource mix.  

“We’re trending toward the top range of the plan if I think about load growth, capacity accreditation,” she said.  

Aubrey Johnson said MISO believes stringing 765-kV lines affords it more flexibility going forward and is preferrable to MISO recommending three 500-kV lines, three double-circuit 345-kV lines, or six single-circuit 345-kV lines for every single-circuit 765-kV.  

On the other hand, MISO’s annual transmission planning cycle shows a preliminary $5.5 billion in more routine investments. (See Early MTEP 24 Designates $5.5B in Transmission Spending.)  

However, Executive Director of Transmission Planning Laura Rauch said MISO’s information shows load growth is gaining momentum and she expects future annual transmission packages to include more spending on local transmission projects.  

MISO’s lead planners Aubrey Johnson and Laura Rauch | © RTO Insider LLC

Members to MISO: More, Please

Some MISO members said the proposed 765-kV lines aren’t a match for future changes.  

Clean Grid Alliance’s Beth Soholt said despite the billions of dollars in proposed projects, MISO needs “to keep going.” She said two of MISO’s three transmission planning futures are too conservative, especially considering recent load growth.  

Soholt urged MISO to recommend and the board to approve the second portfolio expeditiously.  

“There is a significant cost to not building transmission in a timely manner,” she said.  

Xcel Energy’s Drew Siebenaler said while the first portfolio was “groundbreaking” and the second “has the potential to set us up for the energy future,” MISO should plan even more transmission.  

The Grain Belt Express Question

Invenergy’s Arash Ghodsian asked MISO leadership to factor in planned merchant HVDC lines, like the Grain Belt Express, into LRTP efforts. MISO has said it will conduct a sensitivity that includes Grain Belt operations into its modeling but has not committed to rearranging the second portfolio to account for the merchant HVDC line.  

Mark Johnson acknowledged publicly that Invenergy sent a letter to the MISO Board of Directors arguing the RTO is deficient in its LRTP planning because it has not contemplated the $7 billion, 5-GW Grain Belt Express in its latest LRTP portfolio.  

“MISO does its very best to ensure that it has a very open and transparent process,” Johnson said, encouraging stakeholders to participate in MISO’s public planning meetings and voice concerns.  

WPPI Energy’s Steve Leovy also said he’s worried about “MISO planning over projects” like the Grain Belt Express.  

Invenergy’s letter said there is “no justification in the MISO tariff or otherwise for an inefficient planning process that disregards privately funded infrastructure development happening in MISO’s own footprint.”  

“By ignoring the parallel efforts of merchant transmission developers in its LRTP, MISO has demonstrated an ongoing failure in planning,” Invenergy wrote. The company estimates MISO’s first LRTP portfolio alone contains more than a billion dollars in unnecessary costs because it ignored advanced-stage interregional merchant transmission.  

Invenergy said MISO’s failure to include merchant HVDC lines is distorting its required cost-to-benefit analyses.  

“It is time for the board to step in and prevent further waste, delay and policy outcomes inconsistent with those set out by” the Department of Energy, FERC, NERC and Congress, Invenergy told MISO directors.  

Members Want Future Discussions on LRTP III’s Cost Allocation

At the March 20 Advisory Committee meeting, some MISO members asked that a future discussion be devoted to the cost allocation of the third LRTP portfolio, which will focus exclusively on MISO South transmission projects. 

Regulators of states with Entergy companies have asked MISO to use an allocation that assigns 90% of costs based on adjusted production cost savings and avoided reliability projects, with the remaining 10% billed to new generation that interconnects in MISO South based on a flow-based methodology. (See Entergy States Debut Long-range Tx Cost Allocation Proposal, MISO Members Unconvinced.) MISO, on the other hand, has proposed using a blend of a 50% postage-stamp allocation to load and a 50% allocation to the local transmission zone for MISO South LRTP projects. 

At any rate, the third LRTP portfolio is poised to use a different cost allocation than the first two Midwestern portfolios, which employ a 100% postage-stamp allocation to load. Any new cost allocation proposal will have to pass FERC muster.  

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MISO Members Doubt Severity of Long-term RA Alarm Bells

DALLAS — MISO members appeared skeptical at their quarterly meetings that the RTO is destined to face capacity shortfalls before 2030.  

MISO Advisory Committee members at a March 20 meeting cast doubt on predicted shortcomings from both NERC’s 2023 Long-Term Reliability Assessment and MISO’s latest version of its Reliability Imperative report. 

MISO was elevated to a high-risk area by NERC late last year; the agency predicted the footprint would grapple with a 4.7-GW shortfall by 2028.  

And last month, MISO warned that members are powering down dispatchable units too quickly and aren’t building equivalent generation able to pick up the slack on the grid. (See MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report.) 

Minnesota Public Utilities Commissioner Joseph Sullivan said capacity shortages projected in NERC reports haven’t transpired, while some regions previously designated as low risk have experienced blackouts. He said state commissions and utilities have cooperated to delay retirements and ensure resource plans are sufficient.  

The Michigan Public Service Commission on March 15 cited resource adequacy worries when it rejected Consumers Energy’s early termination requests on two power purchase agreements with biomass plants. The commission said that “relying on unpredictable markets for replacement supply outside of a comprehensive integrated resource planning process in this manner entailed an unacceptable level of risk.” 

Sullivan also said the Organization of MISO States and MISO’s annual RA survey “affords more context and granularity” than NERC reports.  

The Union of Concerned Scientists’ Sam Gomberg agreed that states historically have kept the lights on and that NERC’s projected shortfalls haven’t emerged.  

“I think there’s a lot of reactionary effect when we see our region in red. But it’s NERC’s job to keep these fires lit. … This is not to obviate the sense of urgency,” Gomberg said. “I want to emphasize the role of the states.” He said he had faith that states will help MISO “get over the hump” of turbulent years of thermal retirements and replacement with clean power sources. He also said NERC’s report seemed flawed because it relies on a drop in resource additions by 2028.  

The Union of Concerned Scientists’ Sam Gomberg | © RTO Insider LLC

Gomberg also said he noticed MISO is working on several initiatives NERC suggested.  

“Perhaps the sky is not falling, but it does help emphasize to regulators that our plans in place are working,” WEC Energy Group’s Chris Plante said.  

But Michelle Bloodworth, of coal trade organization America’s Power, said it’s well known that solar and wind generation cannot provide the six operating attributes MISO has singled out as critical to the system. She said the premature retirement of mostly coal resources is connected directly to the reliability crisis.  

MISO has defined six system reliability attributes as vital to the system, including availability, rapid start times, the ability to deliver long-duration energy at a high output, and providing voltage stability, ramp-up capability and fuel supply certainty. (See MISO: Attributes Work Won’t Result in New Obligations on Retirements, Interconnection Queue.)  

Bloodworth said it’s a wake-up call that NERC raised MISO from “elevated” to “high risk” in its latest assessment. She advised MISO to be “cautious about any thermal generation that is retiring, not just coal.”  

Clean Grid Alliance’s Beth Soholt said both the NERC Long-Term Reliability Assessment and MISO’s Reliability Imperative struck an unnecessarily catastrophic tone.  

“I think our sector would rather have a tone of ‘this is what needs to be done’ rather than ‘the sky is falling’ alarmist [rhetoric],” she said.  

Soholt also said MISO and states could do more to make sure energy storage can serve as a source of dispatchable power in the fleet transition.  

However, Bloodworth said she commended the “sober” tone because there is cause for concern, with 19 GW of MISO’s coal fleet set to retire in the next five years and even new natural gas investment threatened by EPA’s proposed carbon emissions rule.  

“A megawatt is only as good as the people it’s delivered to,” Bloodworth said.  

Gomberg said coal use is “devastating from the cradle to the grave” in terms of toxic environmental and deadly public health consequences.  

“The quicker we can move on from coal, the better,” he said.  

Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, said it would be helpful if utilities were more open with customers about their resource plans.  

Travis Stewart, representing the Coalition of Midwest Power Producers, said in addition to new resources, MISO needs new transmission, especially merchant HVDC lines.  

“You can read that same headline for the past 10 years,” OMS Executive Director Marcus Hawkins said weeks earlier about MISO and NERC warning about a pending shortfall in the next three to four years.  

But state regulators are working relentlessly to ensure that “MISO’s worst nightmare doesn’t come true,” Hawkins said at the Gulf Coast Power Association’s March MISO-SPP conference. However, Hawkins said new load growth and the hastening fleet transition means different factors are at play in estimating capacity adequacy.  

“We’ve had quite an erosion in our resource adequacy,” MISO CEO John Bear told board members and stakeholders at MISO’s March 21 board meeting.  

Bear said the grid operator is going to have to ensure it conducts sufficient analysis to be confident in its decisions’ safety before moving ahead on more RA initiatives. Nevertheless, he said, moving ahead is a must.  

Bear predicted MISO won’t have glowing news to share in its next RA survey due in summer in partnership with OMS. He said RA concerns are compounded by significant load additions across the footprint and system stability concerns.  

“I want to remind people, as we move forward, there are going to be very new risks,” Bear said.  

Iowa Utilities Board member and OMS President Josh Byrnes agreed the RA risks are real, and the solutions are complex; however, he urged fellow commissioners and members to “stay positive.”  

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FERC Accepts NYISO Proposal to Coordinate Queue, Transmission Processes

FERC on March 19 approved NYISO’s proposed tariff revisions aimed at harmonizing its generator interconnection and transmission planning processes (ER24-951). 

The changes are intended to improve coordination between NYISO’s Class Year study in its Large Facility Interconnection Procedures with the facilities study for transmission projects under its Transmission Interconnection Procedures. Additionally, the revisions amend the base case inclusion rules in the ISO’s Small Generator Interconnection Procedures to ensure more precise accounting of identified interactions. 

NYISO argued the changes will prevent transmission projects from being studied in isolation from projects in the interconnection queue or undergoing overlapping evaluations, thereby improving the efficiency of each process. 

The ISO’s proposal included revising security posting requirements for transmission projects. Developers will be required to post security for upgrades before, rather than after, executing a transmission interconnection agreement. This change is expected to reduce the need for restudies of network upgrade facilities, which should make it easier for projects to be included in the existing system representation for the next Class Year study, the ISO argued. 

“We find that [the revisions] would accomplish the purposes of Order No. 2023 by improving the efficiency of NYISO’s interconnection request process and the accuracy of the models used in NYISO’s interconnection studies,” the commission said. “This will contribute to increasing the overall efficiency of the interconnection process, which will help ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.” 

The proposal had been in development since 2022, before Order 2023 was issued, as one of the ways NYISO sought to unclog its interconnection queue. After Operating Committee approval in December of that year, several events led the ISO to delay bringing it before the Management Committee, including Order 2023 itself, as it wanted to ensure the proposal did not conflict with the order. The MC unanimously endorsed the proposal in October. (See “Interconnection & Transmission,” NYISO Management Committee OKs $195M Budget, 5.6% Rate Increase.) 

NYISO submitted an interim, “partial” compliance filing for Order 2023 in November. The deadline for its full compliance filing is April 3. The order, issued in July, directed grid operators to change their interconnection procedures from first-come, first-served to first-ready, first-served. 

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Report Calls for More Policies to Bolster Domestic Solar Manufacturing

The U.S. needs to take action beyond incentives from the Inflation Reduction Act and the CHIPS and Science Act if it wants to create a truly domestic solar manufacturing industry, according to a report released by the Solar Energy Manufacturers for America (SEMA) Coalition on March 20. 

SEMA’s members produce solar panels and their components in the U.S.; they include firms such as First Solar, Q-Cells and REC Silicon. The organization hired Guidehouse Insights to produce the report, “Inflection Point: The State of US PV Solar Manufacturing & What’s Next.” 

The IRA generated a lot of excitement about increasing the domestic share of the solar supply chain, with policies such as a 10% bonus to the investment tax credit for using domestic panels, but the country’s competitors have responded, SEMA Executive Director Mike Carr said on a webinar. 

“Without a U.S. policy response to the current influx of imports in both components and finished products, resulting in significant oversupply, recent factory announcements will likely not come to fruition,” the report said. “While the groundwork has recently been laid for a strong domestic solar manufacturing ecosystem, significant gaps remain and present a threat to its long-term viability.” 

Solar has gotten cheap enough that utility-scale capacity should make up about 40% of all generation installed this year, and that share could grow to 60% over the next decade, the report said. Higher prices from higher tariffs and other policies incentivizing domestic consumption would not be enough to derail that, SEMA argued. 

“This steady state of deployment is really kind of disconnected from the module prices,” Carr said. “Those have bounced around a fair amount in recent years, including hitting new lows this year, and it really doesn’t affect the trajectory one way or another.” 

The effective duty rate on imported solar has dropped from 9.6% in 2021 to just 0.4% last year, but even a ban on imports would not be a boon for domestic manufacturing, as this year’s demand is vastly outweighed by supply because of stockpiling, said Guidehouse Senior Research Analyst Peter Marrin. 

“Even if these imports stopped today, we still have a huge problem. … We have about 2.4 to 2.7 times the amount of module supply relative to demand,” he said. “So, we’re that overstocked.” 

Solar photovoltaic panels’ supply chain starts out with turning mined quartz into high-quality polysilicon; pulling that into ingots; slicing wafers from the ingots; producing PV cells; and then assembling the module. China dominates the global manufacturing of all those steps, but its share is highest in ingot and wafer production. 

“The U.S. currently could produce enough polysilicon to make about 20 GW of crystalline silicon products each year, but the country lacks critical next-step manufacturing facilities for the various refinement and component fabrication steps in the solar cell manufacturing process,” the report said. “The U.S. also lacks capacity to manufacture ingots, wafers and cells, and therefore is entirely dependent on global suppliers for these components.” 

A decade ago, the U.S. had nearly a dozen facilities involved in ingot and wafer production that each could produce up to 500 MW annually, but those since have shuttered and now those highest-cost parts of the manufacturing process are the least subsidized by the IRA, the report noted. 

“As a direct result of IRA provisions, the U.S. is seeing a significant increase in announced cell manufacturing and module assembly capacity,” the report said. “If even half of this announced capacity comes online, the U.S. could produce enough cells and modules to meet nearly 100% of its new solar demand through 2027.” 

Those domestically produced panels and modules still would rely on Chinese wafers and polysilicon, leaving the industry vulnerable to price shocks and possible disruptions from geopolitical disputes. 

“Domestically produced solar modules can be roughly 30 to 50% more expensive to produce than imported ones, but various provisions in the IRA aim to reduce this gap by promoting economies of scale and vertical integration,” the report said. “Focusing investments on developing the cutting-edge equipment, knowledge and workforce needed for a strong domestic supply chain can further reduce these costs in time.” 

Beyond tariffs and enforcing anti-dumping trade laws, policymakers can move the ball forward by setting stronger standards for bonus tax credits and using federal procurements to induce demand for domestic production, the report said. The 10% bonus tax credit has not been implemented ideally, Carr said, and the Biden administration has seemed receptive reviewing it.

“More than more than half of the value of the module can be produced outside of the United States, and you can still have your module considered domestic,” Carr said. “And we think … that is not really a recipe for success.” 

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NERC Standards Teams Pushing to Meet FERC Deadlines

The team developing a reliability standard requiring internal network security monitoring (INSM) at some grid cybersystems saw two “big wins” in the recent ballot round for the standard despite it failing to reach the threshold for passage, leaders said at the monthly meeting of NERC’s Standards Committee on March 20. 

Stakeholders returned the proposed standard, CIP-015-1 (Internal network security monitoring), with a 48.52% segment-weighted vote for approval in the ballot round that ended earlier that week, short of the necessary two-thirds majority. (See Industry Sends Back NERC Cyber Monitoring Standards.) FERC has ordered NERC to submit standards requiring INSM by July 9. 

Valerie Ney, the standard development team’s vice chair, reminded SC members that the result represents a significant improvement over the last ballot round in January, when CIP-007-X (the team’s previous attempt at adding INSM to an existing standard) received a segment-weighted vote of just 15.42%. She observed that the choice to create a new standard received overwhelming support, with 97% of respondents who expressed an opinion on the change approving. 

Ney noted that stakeholders were also supportive of the SDT’s decision to remove electronic access control or monitoring systems and physical access control systems from the standard’s applicability list when they fall outside an entity’s electronic security perimeter. Comments on this change were 100% supportive.  

Thad Ness, the SDT’s chair, acknowledged that the authors “got a lot of feedback” on the requirement that entities identify the network locations facing the greatest security risks and how they will develop their monitoring capabilities, and said the next iteration may have to “be a little clearer on that front.” He also mentioned that respondents pointed out “operational limitations” with the standard’s communication requirements, in that some substations “might not have a strong bandwidth to get this data and move it around.” 

“We really thank the industry for providing some really good comments,” Ness said. “I do believe this is going to have an abbreviated posting [timeline] for the next round … so we are up to the task of doing any outreach to make sure the industry is aware of what we’re doing with the changes and can get the support for this.” 

The SDT will meet March 21 to discuss its next moves. 

IBR, Cold-weather Ballots Approved

Committee members at the meeting voted unanimously to post four other proposed reliability standards for ballot and comment periods. 

First up were two standards under development by Project 2020-02 (Modifications to PRC-024 — generator ride-through). The project is intended to address performance issues identified in inverter-based resources, causing generators to trip offline unexpectedly and potentially cause grid stability challenges. 

PRC-029-1 (page 60 in the agenda) is a new standard that creates ridethrough requirements specifically for IBRs, while PRC-024-4 (page 14) updates ridethrough requirements found in the existing PRC-024 standard applicable to synchronous resources. Both standards will be posted for a 25-day comment period; the committee authorized shortening the typical 45-day period at its December 2023 meeting because the project is responding to FERC Order 901, which imposed a Nov. 4, 2024, deadline for IBR performance standards addressing IBR performance issues. 

Also approved for a 25-day comment period was PRC-030-1 (Unexpected inverter-based resource event mitigation) (page 83), under development by Project 2023-02 (Analysis and mitigation of BES IBR performance issues). The proposed standard, also developed in response to Order 901, would require “analysis and mitigation of unexpected or unwarranted protection and control operations from IBRs.” SC members approved a waiver for this project at the December meeting as well. 

Finally, the committee authorized the posting of TPL-008-1 (Transmission system planning performance requirements for extreme weather events) (page 96) for a 45-day initial formal comment period. This standard would require entities to develop benchmark planning cases based on previous extreme cold or hot weather events, use those cases to plan for future extreme events, and develop corrective action plans when performance requirements for extreme heat and cold are not met. 

Project 2023-07 is also developing this standard in response to a FERC directive, in this case Order 896 requiring a standard to be submitted by December 2024 addressing cold weather performance concerns. Although the SC did grant the project a waiver allowing shortened comment and ballot periods, the SDT elected not to pursue this option. NERC Manager of Standards Development Jamie Calderon explained that “the team wanted to ensure that there [were] substantive comments” to help shape their work in the coming months. 

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Calif. Looks to Streamline Process for Issuing NEVI Funds

California officials are exploring how to improve the dispensation of hundreds of millions in federal funding to build a public network of electric vehicle charging stations.

At a March 12 workshop, officials from the state’s Energy Commission (CEC) and Department of Transportation (Caltrans) sought feedback on how dispensation worked during the first round of grant solicitations from the National Electric Vehicle Infrastructure (NEVI) program, which aims to build a national network of chargers to encourage EV uptake.

A part of the federal Infrastructure Investment and Jobs Act (IIJA), NEVI will provide $5 billion to states to build 500,000 direct current (DC) fast chargers that will enable data collection, reliability and long-distance travel in zero-emissions vehicles. California’s share of the funding is expected to be $384 million allocated over five years (See Federal Plans to Electrify Highway Corridors Advancing.) 

The first tranche of funding was released in October 2023 and awards are expected to be granted in late April. The second round of funding is slated to be released in August, and applications are due by November to the Joint Office of Energy and Infrastructure.  

The workshop provided an opportunity for the CEC and Caltrans to present and solicit feedback on the proposed structure and requirements for the second NEVI grant funding opportunity based on comments received about the first solicitation.  

Structure of the Plan

EV charging projects must meet basic requirements to be eligible for NEVI funding. Key among them is the requirement for stations to be publicly available, located no more than one mile from a highway designated as an “alternative fuel corridor” and placed no more than 50 miles apart from each other. The stations also must contain at least four DC chargers of at least 150 kW per port.

Under the 2023 California NEVI Deployment Plan, designated highway corridors are broken into segments containing one or more charging stations. Groups of corridor segments then are identified by geography and ranked to fund the highest-priority areas first. Only private entities, including investor-owned utilities, are eligible to bid into the competitive solicitations to build, own and operate charging stations.

Speaking at the workshop, Jane Berner, strategic investment analyst at the CEC, identified 21 corridor groups in California ranked by characteristics that determine whether the segment is high-priority, including the percentage of the corridor located in a disadvantaged or low-income community, the number of chargers needed along the corridor to complete the 50-mile range requirement and whether the area interlaps with tribal land.

NEVI requires that at least 50% of funded chargers be in disadvantaged or low-income communities and at least 40% in Justice 40 communities, those that are marginalized by underinvestment or overburdened by pollution.  

California’s first solicitation awarded $40,500,000 in grants to six corridor groups. The second round of solicitations offers $110,220,000.

At the workshop, planners discussed two options for establishing corridor groups in the second round: two-part and standalone projects. The two-part project plan would involve breaking 16 corridor groups into priority-based halves. Participants would complete one application to build stations in as many corridor groups as they choose and could be awarded up to three areas. This approach offers available funds more manageably and enables faster deployment and advanced planning, Berner said.  

The standalone option is smaller, involving application to only one corridor group, which could enable a larger applicant pool, Berner said.  

Ranking the corridors by the two-part project structure, a group consisting of Bay Area interstates and I-80 to Sacramento received the highest score, followed by Southern California I-8 and I-10 to the state’s eastern border, and Northern coastal corridors.  

Stakeholder Feedback

Kristian Corby, deputy executive director of the California Electric Transportation Coalition, asked to work with the CEC and Caltrans on utility verification forms — required to inform the level of grid readiness for a project site — to ensure utilities can respond to the volume of forms in a timely manner.

“PG&E got something like 70 requests for completing that form in the lead-up to the past solicitation deadline,” Corby said. “That type of inundation is very difficult for the utilities to process quickly and to give the applicants good information, so we’re working on some recommendations for that.” 

Corby also was concerned that allowing participants to choose between higher- and lower-ranked groups in the two-part project structure would leave out some areas, though he suggested lower-priority groups could be offered as standalone projects.  

“This does open up, I think, the risk that we might get some particularly lower-ranked corridors that maybe no one applies to,” Berner said. “We’ll have to figure out how we’ll handle that case and it think it would probably be that we would just handle them separately.”  

The CEC and Caltrans are developing California’s 2024 NEVI deployment plan. Comments on the plan are due March 25.