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October 1, 2024

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SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022

SPP told stakeholders last week that it has chosen a hybrid approach to improve its transmission- and congestion-hedging markets, focusing first on equitably allocating congestion rights instruments and then increasing the pool of awards available.

The proposal marks a change in direction from the initial focus on counterflow optimization. Stakeholders were unable to coalesce around the market mechanism despite three years of effort.

The SPP Board of Directors in April directed staff to survey members, the regulatory stakeholder groups and the RTO’s Market Monitoring Unit (MMU), gather feedback, and bring a final recommendation to the board’s October meeting. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)

Staff will bring a proposal to the board later this month, but they will also ask that a vote be delayed until the directors meet again in January. That will give the board and state regulators an opportunity to provide the policy direction that will go into developing tariff changes. It will also give staff more time to build stakeholder support for the proposal and gather additional feedback.

“I know the board values input from the members, but we feel that this is taking a look at the entire picture and not just focusing on one thing,” COO Lanny Nickell told the Markets and Operations Policy Committee Oct. 10. “We feel pretty confident and pretty good on the direction where we’re going.”

Micha Bailey 2022-08-09 (RTO Insider LLC) FI.jpgMicha Bailey, SPP | © RTO Insider LLC

Nickell complimented staff for their recent work “to get some movement on resolving the concerns and issues around the congestion-hedging process.” Congestion-hedging supervisor Micha Bailey said staff talked with stakeholders who provided input to gain a deeper understanding of their concerns.

“We kept hearing some of the same themes … Fair, transparent, equitable, needs to provide a hedge. And as we looked at those and as we were hearing the same common themes, we wondered, ‘What can staff propose?’” Bailey said. “What can we propose that’s going to help SPP today and also in the future, recognizing that generation is changing.”

Bailey said “hybrid” was the new buzzword, replacing counterflow optimization. That market mechanism, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency. (See SPP Continues its Counterflow Optimization Work.)

The hybrid proposal will increase the number of hedges available as the Holistic Integrated Tariff Team intended when it approved a package of 21 improvements to the SPP grid in 2019, Bailey said.

“We’re going to increase equity and fairness within the congestion-hedging process,” Bailey said. “We’re focusing on bringing those who are getting nothing up right. When you introduce equity, some entities [receiving hedges] … have to give up some to allow other entities to come in. We need to focus on a short-term solution that that will help entities that are getting nothing get something.”

He compared the current process to a buffet line, where excess auction revenue is distributed to participants, who already have hedges, in what amounts to a load-ratio share.

“You’re double dipping … at the end of the year, you’re getting something on top of what you want,” Bailey said. “In the buffet line analogy, which we’ve heard time and time again, you’re going two to three times in the buffet line. Those sitting with empty plates at the end of the year, they’re the ones who should be getting the ARR excess revenue.”

Staff’s recommendations include:

  • Resetting long-term congestion rights (LTCR) awards every 10 years to give market participants more opportunities to gain the hedges.
  • Modifying the LTCR’s second round of nomination capacity from 100% to a more equitable incremental percentage up 100%.
  • Changing the auction revenue rights (ARRs) process’ annual first round nomination capacity calculation to more fairly allocate ARRs.
  • Revising the ARRs’ first round nomination capacity from 50% to an incremental percentage up to 50%.
  • Distributing excess auction revenues.

SPP also plans to update its load and generator modeling to better align them with transmission service that is studied, review the planning process’ firm transmission assumptions, and provide further stakeholder education.

“We need to involve the upstream applications from congestion hedging because congestion hedging starts with firm transmission service,” Bailey said.

While stakeholders generally expressed support for the proposal, American Electric Power’s Richard Ross, who chairs the Market Working Group that put a lot of time and effort into resolving the issue, offered a counterpoint.

“I don’t hold out much hope for the stakeholders suddenly going, ‘Oh yeah. This is great.’ But, you know, we’ll see,” he said, offering his own praise for staff’s work.

MMU Executive Director Keith Collins said the hybrid proposal addresses the monitor’s concerns and is a good package.

“There’s no silver bullet in this process. The approach that Micha is outlining is like a scattershot approach … but it applies that basic set of points that Micha raised of how we improve the equity so that we can improve affordability,” Collins said. “We reduce the effects of the buffet line. You want people to go through the line and if you can do that at least a couple of times, you’ll allow folks to be able to get more if you’re at the back of the line.”

Members Address Resource Adequacy

MOPC approved five revision requests (RRs) related to resource adequacy and a planning reserve requirement (PRM) that the board and state regulators recently raised from 12% to 15% for the summer season, effective next year. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

The committee had to first reconcile competing versions of a revision request (RR515) that lays out the process by which load-responsible entities (LREs) may qualify for and receive exemptions of the deficiency payments assessed to those that have not met the tariff’s resource adequacy requirement, if they have met the applicable criteria.

Members eventually sided with the version brought forward by the Supply Adequacy Working Group (SAWG), which allows a three-year exemption from a deficiency payment and adds triggers if the PRM was increased the year before. To qualify, LRES must demonstrate they had adequate capacity to meet the resource adequacy requirement based on the prior effective PRM and show enough capacity to meet the upcoming season’s forecasted load and a prior effective PRM.

Under SAWG’s version, LREs meeting the PRM, must demonstrate that as of April 5 of the current year, sufficient capacity for purchase has not been identified on bulletin board or demonstrate a contracted obligation to purchase capacity from a generator/developer or demonstrate it has a pending request for interim, surplus or replacement generator interconnection service that is of sufficient size.

The Cost Allocation Working Group, comprised of regulatory staff and which reports to the Regional State Committee, offered the same language, with the exception of using “and” instead of “or” before “demonstrate it has a pending request …”

The motion to endorse RR515 cleared the two-thirds threshold at 72.5%.

Casey Cathey, SPP’s director of system planning, said staff has already begun developing the principles for deficiency payment exemptions.

“[The exemption] needs to be realistic and must support reliability improvements,” he said. “We need to ensure the policy meets the proper incentive for the reserve margin. When it’s increased, we need to make sure we’re still sending the right signal for reliability purposes. We want to create a positive policy that FERC would agree to and approve.”

A bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU having the rights to review the data.

SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation (LOLE) study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year).

Stakeholders also approved RR508, which allows LREs to use deliverable capacity to meet their winter season obligation as well. SPP said with more LREs seeing increased loads in the winter season and some becoming winter peaking, it became apparent that the LREs should be able to use the same method to meet their winter obligations.

MOPC also endorsed three other RRs:

  • RR513: Removes barriers to requesting surplus interconnection service by permitting expansion of existing substations to a location near enough to be considered part of the existing substation. Equipment additions required at the interconnection substation classified as network upgrades would not invalidate the request and would further permit added or modified “system protection equipment” at a remote substation.
  • RR516: Implements the planning reserve margin’s increase from 12% to 15%.
  • RR517: Creates a business practice documenting SPP’s consideration of a long-term service reservation as evidence that interim interconnection service or interconnection service subject to limited operations associated with a long-term service reservation causes no adverse thermal or voltage impacts to the transmission system. It also documents that the generating facility can continue to operate, provided there are no adverse short-circuit or stability impacts.

RRs 508 and 513 passed together unanimously and RR517 passed with 93% approval. RR516 barely passed at 67.9% approval, although it simply adds the 15% PRM to the tariff. AEP opposed the proposal during the SAWG vote, saying imposing an immediate 25% increase to the LRE reserve margin, given SPP’s generator interconnection queue backlog and other challenges faced by LREs, “sets a dangerous precedent and represent a poor implementation of capacity rules changes.”

Members Endorse 2022 ITP

MOPC approved a pair of working groups’ recommendation to endorse the 2022 Integrated Transmission Plan and its assessment report. The 2022 assessment report documented the 2022 plan as being complete.

The Economic Studies (ESWG) and Transmission (TWG) working groups said the reliability-only portfolio is smaller than previous ITP plans, thanks to the $3.4 billion in new transmission projects being placed in service between 2015 and 2019. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.

The 2022 study was re-baselined in April to get back on schedule by only performing the reliability assessment. (See “Tx Planning Changes Pass,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022.)

ITP studies (SPP) Content.jpgSPP has four ITP studies in process. | SPP

 

During the re-baselining process, staff worked with the ESWG and TWG on a comprehensive review of the ITP’s governing documents to find efficiencies and improvements to help meet future assessment deadlines. The work resulted in four to six weeks of time savings.

SPP staff is currently juggling three other planning studies: the 20-year long-term assessment and the 2022 and 2024 ITPs. The 20-year assessment is the only study that is still behind, and that is only by one month. Staff said they will have to reduce scope to meet its April 2023 deadline.

Cathey complimented the ESWG for developing 2024 ITP futures that reflect industry trends in arriving at realistic renewable energy projections.

The stakeholder group’s base case foresees solar capacity growing from 7.1 GW to 14 GW between years five and 10 and wind increasing from 43.8 GW to 49.9 GW. Its emerging technologies future has greater projects of 11 GW to 22 GW and 48.2 GW to 54.9 GW, respectively. The ESWG expects storage to grow to as much as 8.8 GW in 10 years, based on a percentage of solar capacity.

“For a number of ITPs, we feel like we’ve gotten better at hitting the future. That said, the last few cycles, we’ve been hitting 10-year numbers within two years,” Cathey said. “We believe, especially given the Inflation Reduction Act and everything that’s going on in the industry, that this is probably the first one that really is taking a leap. We’re kind of all on board that this is a better prediction of what we’re actually going to see in the next five to 10 years.”

The ESWG evaluated more than 35 projections, using input from SPP’s GI queue, the U.S. Energy Information Administration’s annual energy outlook, and extrapolated 2022 ITP input from its members and the Market Monitoring Unit to arrive at its numbers.

The group plans to bring the final 2024 ITP scope document to MOPC in January for its approval.

Cathey also said the long-term assessment, due in the spring, should inform more of the assumptions that will be made in the 2025 ITP and in the consolidated planning process.

Increasing BTM, DR Resources’ Visibility

MOPC approved a pair of Operating Reliability Working Group (ORWG) revision requests designed to give SPP’s balancing authority visibility into controllable, dispatchable, non-registered behind-the-meter (BTM) and demand response data, referred to as “cats and dogs” by some stakeholders.

The ORWG said RR520 improves the BA’s ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected load-responsible entities (LREs). Under RR512, LREs will submit used and unused capacity on BTM resources that have qualified as accredited capacity that can be used to respond to emergency conditions.

The first change passed with 84.4% approval and 10 abstentions. RR512 passed unanimously, also with 10 abstentions.

The RTO said its tariff exempts certain generations of small size from full market registration. Because some entities don’t have the proper technology to meet market registration data requirements, SPP will allow data submission through its managed file transfer system but plans to also use its application programming interface before next February’s implementation deadline.

“[Being] registered is key, whether through the market or modeled in [the energy management system], but it is not a requirement for all units that are BTM,” SPP’s Yasser Bahbaz, director of markets development, told stakeholders. “If these resources are not registered, then we are not requiring or receiving telemetered information … Your BTM units may be modeled in the reliability model but not registered. In this case, we still need to know about the info requested in these RRs.

“Knowing that capacity that’s available is really important to SPP,” he said.

“We need SPP’s real-time visibility into what’s out there,” Nebraska Public Power District’s Ron Gunderson, the ORWG’s acting chair, said.

The changes are a result of the 2021 winter storm, which required SPP to rely on energy transfers from MISO to meet demand.

The MMU registered several concerns with the changes, saying BTM generation and demand response are not adequate for the grid operator to objectively apply its performance-based accreditation but would likely represent a small reliability risk. It disagreed with the grid operator’s legal determination that adding the data requirements to the operating criteria results in enforceability and recommended better definition of various terms.

GI Backlog Down to 405 Requests

Staff told MOPC that they have reduced the number of active requests in the GI queue down to 405 as of September, a 37.8% reduction since their backlog mitigation process began in January with 651 requests. SPP has eliminated 76 active requests since its last update to members in April. (See “Staff Reducing Interconnection Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022).

“We’re happy with the progress we’re making,” the RTO’s Juliano Freitas said.

Generation-interconnection queue (SPP) Content.jpgRenewables dominate SPP’s current generation-interconnection queue. | SPP

 

More than 200 requests have been withdrawn, leaving 222 in progress and another 183 waiting to be processed. The grid operator has executed 33 GI agreements, with four more pending.

But SPP is still in a hole, though not as deep. Staff said they have received and validated another 82 GI requests totaling 17.7 GW of capacity since April. That leaves the current queue at 487 requests totaling almost 96 GW of capacity. Solar requests (210, 45.1 GW) account for the bulk of the new requests.

Freitas said the grid operator doesn’t plan to close the current cluster until its finishes the backlog mitigation plan, still on schedule by the end of 2024. He said SPP is forecasting that it could install more than 50 GW of capacity by 2028.

“We have to keep our eyes on [the current cluster], because we don’t think it’s feasible to study a cluster with 100 megawatts in it,” he said.

NASEB Gas-electric Forum Convened

Charles Yeung, SPP’s executive director of interregional affairs, encouraged members to engage themselves in a gas-electric harmonization forum recently begun by the North American Energy Standards Board.

The forum was convened in August at the request of FERC and NERC. The organizations want NAESB to address a recommendation from their 2021 joint report on the year’s winter storm that calls for improving the reliability of the natural gas infrastructure system in support of the bulk power system. The recommendation focuses on gas-electric information sharing regarding system performance, gas infrastructure reliability during cold weather, and generators’ ability to obtain fuel during extreme cold weather.

“Obviously, SPP alone cannot deal with those issues,” Yeung said, noting many of the items date back to a similar cold-weather event in 2011. “Some of these issues have been brought up before, but the perception of them has changed with the disaster in Texas.”

The forum is tasked with delivering a report that includes concrete actions to increase gas infrastructure reliability, detailed plans to implement the recommendations, and the entities responsible for deploying the changes. The group met for the first time in August and will continue to convene monthly into early 2023.

Among those involved in the forum are former FERC Chair Pat Wood and Department of Energy veterans Susan Tierney and Robert Gee, who, like Wood, also chaired the Texas utility commission.

MOPC Chair Buffington ‘Honored’

AEP’s Ross, who hands out to staff and stakeholders eponymous “Gold Star” awards, complete with certificates of authenticity, unveiled a new “Richard Ross Boot Award” during the meeting.

Ross, jokingly saying he was “booted off” a recent stakeholder conversation, promised to send the first Boot Award to Evergy’s Denise Buffington, who is cycling off the committee as its chair, for her leadership the past two years.

Buffington warned members her term does not expire until Dec. 31. ITC Holdings’ Alan Myers, MOPC’s vice chair, will succeed Buffington next year.

Gold Star awards are also due for SPP’s Bailey, Drew Gilvray and Nikki Roberts in recognition of their work to improve the congestion-hedging process, Ross said. He will bring the awards and certificates to an upcoming meeting.

12 Revision Requests Pass

MOPC unanimously approved a consent agenda with 12 RRs, although nine members abstained:

  • RR492: Provides clarity on the risks, timing and treatment of generator-interconnection requests’ financial securities refunds, cost allocation comparisons and withdrawn opportunities. It also adds a definition to distinguish “equally-queued” versus “lower-queued” priority of GI requests.
  • RR497: Adds further definition to the Project Cost Working Group’s oversight for applicable projects that are funded through direct assignment of cost.
  • RR498: Allows the ESWG to determine whether SPP’s additional incremental generation capacity recommendations should be included in the ITP’s economic model.
  • RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
  • RR500: Clarifies and documents a more efficient and detailed process for submitting late data submittals in the ITP, including a new submittal form to help staff assess impacts. 
  • RR503: Modifies language in the market mitigation sections of the protocols and tariff by removing references to dispatch and “settlement purposes” and replacing them with clarifying language to specify the solution will be used for determining locational margin prices and marginal clearing prices (MCPs). 
  • RR504: Addresses potential inefficiencies in the regulation mileage compensation design by revising the mileage factor calculation and setting the mileage MCP to the resource projected to provide the last mile based on the mileage factor.
  • RR507: Updates the list of transmission services grandfathered agreements.
  • RR510: Revises SPP’s competitive transmission process with changes to the request for proposal’s scoring methodology and deposits and cost calculations sections and adds an additional table to the confidential information treatment section.
  • RR511: Changes the tariff by updating the IEP public report deadline from 14 to 21 calendar days.
  • RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to be $1,500.
  • RR518: Corrects a calculation error in the protocols related to when regulation is not cleared in the real-time balancing market.
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Overheard at EBA Mid-Year Energy Forum 2022

WASHINGTON — The Energy Bar Association last week held its annual Mid-Year Energy Forum over two days at the Renaissance Downtown Hotel to discuss the latest developments in energy law, including West Virginia v. EPA, the Inflation Reduction Act, supply chain issues and hydrogen regulation, among many other topics.

Here is some more of what we heard. (See related stories, W.Va. v. EPA Ruling: ‘Nuclear Bomb’ or ‘Speed Limit’?, Lawyers, Industry Debate Path for Hydrogen Regulation and Can New Revenue Models Unlock Interregional Transmission?.)

Excitement About IRA — but also Trepidation

Panelists expressed enthusiasm about the Inflation Reduction Act, even as they acknowledged its limitations and the significant amount of work it will take to implement it.

The law provides for about $370 billion in funding for clean energy technologies, including electric vehicles and energy storage, making it the most significant piece of legislation passed by the U.S. to address global climate change. But the bill, originally called the Build Back Better Act, was considerably pared down from trillions in incentives and passed via congressional budget reconciliation to avoid a filibuster by Senate Republicans.

Because of the way it was passed, the IRA “deals only with the opportunity to provide — and very substantial, but still — loans, grants and tax incentives,” Jim Wrathall, general counsel for New Energy Equity, said during the forum’s opening general session on Wednesday. It is “using policy solutions that are not market-based; they’re not comprehensive; and they’re not aimed at targets. They’re money upward. We have to build using these tools and make sure they’re successful.”

“It’s really going to be a renaissance in our domestic manufacturing,” said Edward Hild, principal of government relations for Buchanan Ingersoll & Rooney. “I think that’s where this ultimately leads: to manufacturing [on a scale] we have not done here before. … There’s really a desire not to be dependent on China and other countries, and to do things here.”

“We in this room and in this industry have a challenge here,” Wrathall said. “We’re in the first inning with the tools that are being made available. … We have a job to do to make sure we don’t have missteps.” He reminded the audience of Solyndra, the solar panel manufacturer that went bankrupt after receiving loans from the Obama administration and became a talking point for Republicans against renewable energy.

That’s creating a lot of pressure on not just the industry and its lawyers, but also on the Treasury Department, which needs to issue the regulations and guidance for how the law will be administered. Though $28 billion in investments have already been committed as a result of the law, according to Wrathall, speakers during a different panel the next day noted that it left many aspects, such as definitions, for Treasury to decide.

EBA Supply Chain Panel 2022-10-11 (RTO Insider LLC) Alt FI.jpgFrom left: Vanessa Sciarra, American Clean Power Association; William Davis, Capitol Tax Partners; Stacy Ettinger, K&L Gates; and Jessica Lawrence-Vaca, SOLV Energy. | © RTO Insider LLC

 

“I cannot overstate how significant an undertaking this is going to be for the Treasury Department,” said William Davis, a partner with Capitol Tax Partners. “A lot of it are issues of first impression for the Treasury Department; the tax writers in that building and in the IRS. …

“I looked at the Tax Cuts and Jobs Act of 2017; it took three to four years to get all the guidance out on that bill, and [for some aspects], the guidance is still coming out. … So it’s going to be a long process.”

Forced Labor

Also on the panel with Davis was Stacy Ettinger, a partner with K&L Gates, who spoke about the numerous actions taken by the U.S. government by both the Trump and Biden administrations against foreign manufacturers, mainly in the form of tariffs on products shipped from adversaries.

They include the Commerce Department’s investigation into alleged dumping of solar components by China to avoid U.S. tariffs, launched in March. (See Solar Sector Braces for Tariff Probe Impact.)

Bill Magness 2022-10-11 (RTO Insider LLC) FI.jpgFormer ERCOT CEO Bill Magness | © RTO Insider LLC

Also impacting trade with China is the Uyghur Forced Labor Prevention Act, signed by President Biden late last year. The law assumes that certain goods manufactured in China’s Xinjiang province were done so using forced labor, unless U.S. Customs and Border Protection can certify that they were not. The Chinese government is widely suspected of holding Uyghurs, an ethnic minority in the country, in internment camps and using them as slaves.

The law also requires firms outside of Xinjiang to disclose any ties with companies within the province. However, Ettinger said, China has laws that penalize its own companies for complying with what it perceives as the imposition of foreign policy.

“So Chinese suppliers are in a rough spot,” she said. “They cannot agree to language [in a contract] that talks about certification against the use of forced labor because China’s position is, there is no forced labor in China.” Many Chinese suppliers are now refusing to sign contracts for trade with the U.S. “and would rather deal with Europe.”

Ettinger said lawyers should advise their clients to “fix the language [in the contracts.] Don’t talk about forced labor … because the suppliers won’t be able to do it. If they do take that step, the Chinese companies are at risk of action against them. … They’d rather deal with somebody else who doesn’t worry about these issues.”

Transmission’s Moment

Michael Skelly 2022-10-11 (RTO Insider LLC) FI.jpgMichael Skelly, CEO of Grid United | © RTO Insider LLC

Michael Skelly, founder and CEO of Grid United, marveled at the attentiveness of the audience at his panel discussion Oct. 11.

“It may be that this is because transmission is one of the most legally intense aspects of the energy transition. Or as we say — ruefully — in our company, ‘No lawyer left behind,’” he said. “Or maybe we’re just having a moment with transmission. … Transmission was in Esquire magazine. Come on.” Esquire’s article was titled, “The Sexiest Part of the Clean Energy Transition Is Big-Ass Power Lines.”

75 Texts an Hour

Former ERCOT CEO Bill Magness, now senior principal consultant for DNV, recounted that at the peak of February 2021’s — “the largest controlled outage ever seen” — he was receiving about 75 texts an hour. “And most of them were just, ‘You suck!’” he joked.

Talking to the Right People

Sonia C Mendonca 2022-10-11 (RTO Insider LLC) FI.jpgNERC General Counsel Sônia C. Mendonça | © RTO Insider LLC

NERC General Counsel Sônia C. Mendonça said the organization is seeking to broaden whom it talks to.

“One of the things that we continuously ask ourselves at NERC is, ‘Are we doing the right outreach? Are we doing enough outreach?’ The risks in the bulk power system are more and more coming from outside of the bulk power system. So if we continue to talk to ourselves, that’s not going to be a very successful conversation, in terms of mitigating that risk. So we need to expand … constantly to states, other critical infrastructures. And we are always asking ourselves, ‘Who is not at the table?’”

Emergency Planning

Angela Kolar 2022-10-11 (RTO Insider LLC) FI.jpgAngela Kolar, Colonial Pipeline | © RTO Insider LLC

Angela Kolar, chief risk officer of Colonial Pipeline, said her company moved several years ago to use its incident command structure for any kind of emergency. But company officials couldn’t have anticipated the ransomware attack that led it to shut down its gasoline pipeline system in May 2021.

“When you go to your crisis management team, and you have a scenario that [includes] a nationwide pandemic and nobody is working from the office and you have a cyberattack at the same time, people want to ask you when the aliens are invading too,” she said. “It just doesn’t seem practical, until it actually happens to you.”

Kolar said her company attempted to be as transparent as it could following the attack but had to make decisions without knowing how severe the attack was. “We didn’t know if they had gotten into our IT side and our OT side. We shut down the pipeline out of an abundance of caution, until we knew what was going on.”

PJM’s Advice for FERC

Craig Glazer 2022-10-11 (RTO Insider LLC) FI.jpgCraig Glazer, PJM | © RTO Insider LLC

Craig Glazer, vice president of federal government policy for PJM, said the RTO is “disappointed” with FERC’s “piecemeal” approach to planning, with NERC assigned to write reliability standards addressing hot and cold temperatures and extreme weather conditions listed as a factor to be considered by planners in the commission’s Notice of Proposed Rulemaking on transmission planning (RM21-17). Meanwhile, critical facilities planning, including gas-electric coordination, storm hardening and interregional transfer capability goals were not addressed, Glazer said.

“We started this as a way to reform planning, yet this aspect of planning is really piecemeal [and] chopped up. And I think we’re going to look back and say we didn’t address it comprehensively when we had the opportunity to do so. …

“Is there a role for NERC? Yes. Should we proceed to standard setting at this point? No, we don’t think that’s the right thing to do,” Glazer said. “We think we’ve got to take a holistic look at all these issues, and then develop standards rather than piecemealing standards. … We’re really asking the staff and the commissioners to step back, look at the totality of what’s going on and what you’re trying to get done.”

Glazer said PJM has three “asks” of FERC, starting with a “clear policy statement” on the importance of enhanced reliability planning to counter critics alleging RTOs are “gold plating” the system.

“Absent some direction from the federal regulator that all the planning authorities need to focus on this, I think we’re going to be in this finger-pointing exercise … forever,” Glazer said.

Second, PJM is asking FERC to give RTOs a “homework assignment” to identify the enhanced reliability needs in each region and how they plan to address them. “We don’t have that record really anywhere at this point,” he said.

Third, PJM would like FERC to work with NERC and the national labs to identify metrics for determining the minimal interregional transfer capacity.

“It’s not a number. It’s a way to analyze what’s the right level of interregional transfer capability,” he said. “I’ve had commissioners say to me, ‘Just go negotiate with your neighbor on interregional coordination.’ It doesn’t work. One system ends up leaning on another system.”

Glazer also questioned FERC’s call for long-term planning looking 20 years into the future. “Twenty years ago, the commission held a technical conference in Charleston, W.Va., to direct us to build more transmission to move coal-fired generation into Maryland and Baltimore and Washington, D.C.,” he said. “And we actually did come up with a plan to do that, which we had to withdraw. But imagine if we had built that transmission.”

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BOEM Sets California Offshore Wind Auction Date

The West Coast’s first offshore wind auction will take place Dec. 6 for five leases off the Northern and Central California coasts that together could generate 4.5 GW of electricity, the U.S. Bureau of Ocean Energy Management said Tuesday.

The 373,268 acres, or 583 square miles, of deep-sea lease areas will also be the first to require floating wind turbines in U.S. coastal waters.

The sale is crucial to achieving the Biden administration’s recently stated goal of deploying 15 GW of floating offshore wind by 2035, the Interior Department said.

PAC Californa Lease Areas (BOEM) Content.jpgFive areas off the coast of Northern and Central California will be leased. | BOEM

“Today, we are taking another step toward unlocking the immense offshore wind energy potential off our nation’s West Coast to help combat the effects of climate change while lowering costs for American families and creating good-paying union jobs,” Interior Secretary Deb Haaland said in the release.

The final sale notice followed BOEM’s issuance of a proposed sale notice in May for two leases in the Humboldt Wind Energy Area off the coast of Northern California and three leases in the Morro Bay Wind Energy Area off Central California.

The areas hold 5 to 7 GW of total capacity, the National Renewable Energy Laboratory said in June, amid discussions of increasing the state’s offshore wind goals.

The California Energy Commission in August boosted the state’s long-term OSW goal to 25 GW by 2045, potentially doubling anticipated long-term capacity, in response to urging by stakeholders and Gov. Gavin Newsom.

The governor praised BOEM’s action Tuesday, calling it “a historic step today toward achieving [California’s] goal of 90% clean energy by 2035 and moving the state away from fossil fuels.” The state has a 100% clean-energy mandate by 2045; the 2035 goal is an interim target.

“California could not have better partners in our march toward a clean energy future than the Biden-Harris administration,” Newsom said in a statement. “Together, we’re fighting for energy independence and a future free of fossil fuels and full of clean energy sources like offshore wind.”

The bureau’s decision to set a date “sends a powerful signal that the federal agency is moving forward with speed and scale to support California in reaching its ambitious planning goals to deploy up to 5 GW of floating offshore wind power by 2030 and a nation-leading 25 GW by 2045,” Adam Stern, executive director of trade group Offshore Wind California, said in a statement.

BOEM Director Amanda Lefton first announced the news of the decision to issue a final sale notice (FSN) on Tuesday morning during her keynote remarks to the Offshore WINDPOWER conference in Providence, R.I., hosted by the American Clean Power Association.

The FSN was also published Tuesday on BOEM’s California website. In it, the bureau identified 43 eligible bidders it deemed “legally, technically and financially qualified to hold a commercial wind lease offshore California.” They include companies such as Avangrid Renewables, BP US Offshore Wind Energy, Equinor Wind US, Orsted North America and Shell New Energies. To participate, bidders must deposit $5,000,000 by Nov. 12.

The FSN lays out the details of the upcoming auction, lease areas and lease provisions and conditions. One new provision is that “BOEM will offer bidding credits for bidders who enter into community benefit agreements or invest in workforce training or supply chain development; require winning bidders to make efforts to enter into project labor agreements; and require engagement with tribes, underserved communities, ocean users and agencies.”

The auction will be one of many developments needed to get OSW up and running in California in coming years.

Port infrastructure, for instance, remains a major obstacle. The Port of Humboldt Bay is slated to serve the 1.6-GW Humboldt WEA but requires wholesale redevelopment. The CEC gave the historic timber port’s operator $10.5 million in March to begin upgrading its facilities.

The Morro Bay WEA could be served by several ports, including Long Beach near Los Angeles or Hueneme in Ventura County.

The wind ports must be capable of handling the massive platforms expected off California, potentially larger than any yet afloat at 900 feet tall and capable of generating 15 GW each.

Transmission is another issue. The Morro Bay WEA could tap into existing onshore infrastructure that serves the nearby Diablo Canyon nuclear power plant. Humboldt will require transmission to be built over mountainous terrain to reach the Pacific AC Intertie running down the center of the state or an undersea cable traveling more than 200 miles to the San Francisco Bay Area, developers have said.

“The West Coast market will singularly rival those on the global stage and could draw billions in U.S. supply chain investments,” Liz Burdock, CEO of the Business Network for Offshore Wind, said in a statement Tuesday. “However, the U.S. must move with urgency to capture this rare economic opportunity by freeing up critical support for port and transmission investments, and do the hard work to identify and build an American supply chain that will anchor the U.S. as a global industry leader.”

BOEM has plans to open two areas for OSW development totaling almost 1.2 million acres off of Oregon. The Coos Bay Call Area and the Brookings Call Area are 12 nautical miles from shore at their closest points. (See BOEM Moves on OSW Plans for Oregon, Central Atlantic.)

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NC Replaces ‘Dirtiest Diesel Buses’ with Electric and More Diesel

North Carolina is using $30.1 million from its share of the Volkswagen settlement to replace “some of the dirtiest diesel buses in the state,” but only 43 of the 161 replacements will be electric.

However, those buses will account for more than half of the VW funds — $16.5 million — according to a Monday press release from Gov. Roy Cooper’s (D) office. A list of the awards showed that cost could be a key consideration for the smaller number of electric buses.

While the new diesel buses will average out between $105,000 and $125,000, the cost range on the electric buses will be $370,000 to $410,000. Shawn Taylor, public information officer for the Air Quality Division at the Department of Environmental Quality, said that the department had received applications for a range of technologies, electric, diesel and propane, and in some cases, a school district requested both electric and diesel.

He cited cost, infrastructure — specifically, issues with installing chargers — and other local factors as key considerations for individual school districts. New diesel buses must also comply with tighter emission standards than 20- to 30-year-old buses, Taylor said.

They also run on low-sulfur fuel that produces fewer nitrogen oxides and other emissions, according to the Diesel Technology Forum, an industry association.

Cooper said the new buses would be good “for the health and pocketbooks of North Carolinians as we continue on our path to clean transportation. Transitioning to cleaner school buses reduces greenhouse gas emissions, lowers costs to our schools, creates great manufacturing jobs and reduces pollution in our poorer communities.”

Some of the buses being replaced are more than 30 years old and “emit more than 20 times the [NOx] and particulate matter of today’s clean buses,” the press release said. The new buses will cut 126 tons of NOx emissions over their lifetime, the release said.

The new buses will also be going to mostly rural counties, including 80 vehicles heading to “schools in the 37 historically under-resourced counties that DEQ targeted for additional outreach and support during the application process.”

Taylor said the clean bus program has attracted a lot of attention across the state. “Folks are excited to see these buses on the street,” he said.

Oversubscribed 

Reflecting national trends in school bus replacement programs, the North Carolina program was oversubscribed, with DEQ receiving 42 applications seeking more than $58 million for 330 clean school buses, according to the release.

EPA was similarly overwhelmed with 2,000 applications when it announced the first round of funding for zero-emission school buses from the Infrastructure Investment and Jobs Act. In that case, the agency decided to almost double the available funding, from $500 million to $965 million. The IIJA provides $5 billion in funding over five years for the program. (See EPA Doubles IIJA Funding for Electric School Buses.)

The Volkswagen settlement funds come from agreements between the German carmaker and the U.S. Justice Department, the Federal Trade Commission and California after it was found that the company had used “defeat devices” in its cars to cheat on emissions tests. North Carolina received $92 million, based on the number of cars with the defeat devices in the state.

Another $1 million from the settlement has been awarded to state agencies to install Level 2 electric vehicle chargers in public locations, such as state parks, museums, aquariums and state government office buildings, according to the Monday press release. More than 100 chargers will be installed at 25 locations, with 22 located in historically under-resourced communities and 13 being used to charge state government electric vehicles.

In a 2018 executive order, Cooper set a target of having 80,000 EVs registered in the state by 2025 and ordered state agencies to prioritize zero-emission vehicles when purchasing or leasing new cars.

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NREL: Sharp Job Growth Needed to Hit US’ 30-GW OSW Goal

The U.S. will need up to 58,000 full-time workers to meet the Biden administration’s goal of building 30 GW of offshore wind by 2030, according to a new study by the Department of Energy’s National Renewable Energy Laboratory (NREL).

Released Tuesday, the study estimates that reaching the 30-GW goal will require creation of between 15,000 and 58,000 full-time equivalent positions between 2024 and 2030, based on assumptions of 25% and 100% U.S.-made content in the offshore installations, respectively. The industry currently employs fewer than 1,000 workers, DOE estimates.

“The offshore wind energy industry could provide tens of thousands of good-quality clean energy jobs for Americans over the next decade,” Alejandro Moreno, DOE’s acting assistant secretary for energy efficiency and renewable energy, said in a statement accompanying the report. “With this study’s comprehensive findings, we can capitalize on this opportunity and grow a strong domestic workforce for the burgeoning offshore wind energy industry.”

NREL said its estimates include only “the direct and indirect offshore wind jobs associated with development, manufacturing, installation and operation of offshore wind energy plants,” and not additional jobs that could be created in communities supported by offshore development.

The study’s authors said they modeled their scenarios by “assuming a deployment pipeline of awarded, soon-to-be-awarded and anticipated lease areas for fixed-bottom and floating offshore wind projects sufficient to reach 30 GW by 2030,” which were detailed in another NREL report released earlier this year. Fixed-bottom capacity was assumed to be installed on the East Coast, and floating capacity was assumed for the deep waters along the West Coast.

NREL expects the industry to rely on a relatively small domestic workforce for offshore wind farms installed between 2022 and 2025 but foresees U.S.-based jobs expanding after that along with the growth in OSW manufacturing and supply chains and the vessels needed to support installation activities.

The study breaks employment into five industry segments, including:

  • Development, which could see average annual employment of 800 to 3,200 from 2024 to 2030 based on the 25%/100% domestic content scenarios. Job growth in this segment is expected to grow in parallel to increased use of domestic content. “The workforce need is likely closer to the upper limit because the United States has professionals and training programs to support a domestic workforce. Project development is underway, and many development jobs for initial offshore wind projects have been hired,” NREL said.
  • Manufacturing and supply chain, which could support between 12,300 and 49,000 jobs, with the largest contribution coming from factory-level positions related to producing subcomponents, parts and materials for OSW installations. “The extent to which domestic jobs are realized depends on the building of U.S. manufacturing facilities and those facilities leveraging a U.S. supply chain to source subassemblies, parts and materials,” the report said.
  • Ports and staging, which could account for 400 to 1,600 jobs a year, with the largest subset being terminal crews involved in stage components and load installation vessels. “Ports supporting offshore wind energy activities will support economic development in industrial waterfront communities by creating jobs,” NREL said.
  • Maritime construction, with average annual employment levels estimated at between 500 and 2,100, although NREL notes that development of this domestic workforce is “highly uncertain” given the potential for different installation strategies and vessel availability. “Maritime construction workforce needs are estimated to develop slowly between 2022 and 2026, as we expect the initial offshore wind projects may use installation strategies

     with foreign-flagged installation vessels with a larger international workforce. However, if Jones Act-compliant vessels are built to meet future development demand, we expect an increase in the domestic workforce need.”
  • Operations and maintenance, which could grow from 100 to 500 jobs in 2024 to 600 to 2,300 jobs in 2030. “O&M jobs will begin ramping up to support offshore wind energy plants in 2023-2024. O&M roles are needed throughout the wind plant’s life; therefore, workforce needs are cumulative, increasing based on the number, size and commissioning year of projects,” NREL said.

Good Timing

The NREL report also identifies the strategies needed to fill OSW-related jobs, including attracting and training skilled tradespeople; improving awareness of the roles required by the sector; clarifying and standardizing the credentials needed for those roles; helping workers from similar fields, such as offshore oil and gas, transfer into OSW jobs; focusing on developing a local workforce in communities affected by OSW development and prioritizing members of underserved populations; and increasing coordination across states and regions to develop workforce training and education programs.

The report also points to a need for coordination of installation activities across OSW projects to account for the variability in demand for certain types of workers along the timeline of an individual project’s development.

“The types, numbers and geographic locations of jobs vary during an offshore wind power plant’s life and, when considered across the pipeline of projects across the United States, can lead to large variability in workforce demand,” the study said. “Therefore, workers should be trained and hired strategically to alleviate potential peaks and troughs of workforce demand. For example, jobs related to installation activities are temporary, but a large deployment pipeline allows workers to move to other projects if those projects are properly timed.”

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Sunrun’s Virtual Plant Sees Success in ISO-NE Capacity Market

Sunrun (NASDAQ:RUN) is calling its first year in the ISO-NE capacity market a success.

From June to August, the company’s virtual power plant (VPP), made up of thousands of home solar systems across New England, sent more than 1.8 GWh of energy back to the grid, the company said in a recent press release.

The capacity agreement made with ISO-NE back in 2019 was the first of its kind, according to Sunrun.

Chris Rauscher, the company’s senior director of market development and policy, said the VPP was successful at sending power back to the grid on the hottest days, replacing output from fossil fuel peaker plants.

“To operate [a virtual power plant] is to really find that balance, the sweet spot, providing value to the electricity grid and all customers on the grid, and retaining the fundamental customer value … for families who have solar in their homes,” he said.

It’s part of a vision for demand response that has ISO-NE leading in some ways: The grid operator’s passive on-peak DR pathway was what let Sunrun achieve its first-in-the-nation entrance into a capacity market.

“We were the tip of the spear,” said Rauscher. “In the ensuing years, there’s been way more interest from [distributed energy resources], and batteries in particular, in entering the market. We helped prove it was possible.”

2222 Filings Closing the Door?

There’s fly in the ointment for the grand plans of Sunrun and other companies trying to replicate its approach: Order 2222 compliance filings from grid operators that they say aren’t living up to the promise of a “new day” for DERs.

“At this point, we’re feeling disappointed in 2222,” Rauscher said.

For example, NYISO has proposed a 10-kW minimum system limit on DER participation in the markets, which Rauscher says would “obviously completely prevent any residential resource from participating in aggregation.” (See NYISO 10-kW Min for DER Aggregation Participation Riles Stakeholders.)

Sunrun isn’t waiting for FERC to finish ruling on the regional compliance filings though: It’s making plans to increase its work directly with utilities, in so-called “bring-your-own-device” programs.

Unlike working in a capacity market on the supply side, BYOD programs involve working with states and utilities on the demand side.

An entity like Green Mountain Power, a Vermont utility that Sunrun has been working with, will coordinate with Sunrun to dispatch its batteries in the service area when peak demand comes, reducing the amount that its customers owe.

“That’s a really good model, and we really like doing that. But it is different because those savings are constrained to a single load-serving entity as opposed to spread across the market,” Rauscher said.

And there’s another issue: As more states and utilities start utilizing that type of demand program, the ones that don’t have them will be left “increasingly holding the bag,” Rauscher said.

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FERC Report Finds CIP Issues Declining

FERC outlined several recommendations for registered entities to improve their compliance with NERC’s Critical Infrastructure Protection (CIP) standards in a report released last week.

The commission based the recommendations in the Lessons Learned from Commission-Led CIP Reliability Audits report on findings from the latest round of audits performed by commission staff during fiscal year 2022, which ended Sept. 30. NERC and the regional entities also took part, as they have since FERC began conducting CIP audits in 2016.

As with previous years, details about the audits — such as how many audits were performed and which utilities were visited — were not disclosed. According to the report, the fieldwork “primarily consisted of data requests and reviews, webinars and teleconferences, and virtual on-site visits.” During the virtual visits, commission staff interviewed the utilities’ subject matter experts and the utilities demonstrated operating practices, processes and procedures. FERC also interviewed employees and managers who performed tasks within the audit scope and examined entities’ compliance documentation.

This year’s audits produced just five recommendations, the fewest since FERC began issuing the reports and a drop of nearly two thirds from the 14 produced last year. Report authors did not acknowledge the decline in lessons learned or suggest any reason for it, stating only that “most of the cyber security protection processes and procedures adopted by the registered entities met the mandatory requirements of the CIP standards, [although] potential noncompliance and security risks remained.”

FERC’s suggestions encompassed three standards. For CIP-003-8 (Cyber security, security management controls) the commission recommended that utilities re-evaluate their policies, procedures and controls for low-impact cyber systems and related assets.

The report’s authors noted that “certain entities” had misinterpreted the standard’s requirement that utilities test their cybersecurity incident response plan at least once every 36 calendar months. Some utilities had concluded that they did not have to test their plans until 36 months after registration. FERC asserted that this is incorrect: Plans must be tested before registration and at least once every 36 months thereafter.

CIP-003-8 also requires that entities identify all transient cyber assets (TCA) — removable media — that they manage, as well as those managed by third parties, to mitigate the risk of infiltration through inadvertent code transfers from unauthorized sources. This “may not be fully understood,” FERC staff said. The report warned utilities that failure to address these assets poses a “serious risk” of compromise to the bulk electric system.

Detailing the issues with CIP-007-6 (Cyber security, systems security management), FERC staff “noted multiple instances where the treatment of end-of-life or end-of-service … BES cyber assets created potential security and compliance risks.” Some entities were found not to have a patch management process or mitigation plans for these assets or were unaware of the extent of assets on their system that were vulnerable in this way. The authors also discovered that not all entities correctly followed the standard’s requirement that they implement a malicious code prevention program on their cyber systems.

For CIP-010-4 (Cyber security, configuration change management and vulnerability assessments), the report found deficiencies in entities’ adherence to the requirement that they have a vulnerability assessment program. Although utilities “generally included multiple vulnerability assessment elements,” at times they neglected “key elements” in the process, potentially leaving them unaware of dangerous vulnerabilities, FERC said.

Finally, staff reiterated the standard’s recommendation that entities “review and validate controls used to mitigate software vulnerabilities and malicious code on TCAs managed by a third party,” noting that “some entities accepted attestations from third parties without performing due diligence” to validate the TCAs’ risk level.

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Ohio Alliance to Support Appalachian Hydrogen Hub

Leaders of the Ohio Clean Hydrogen Hub Alliance (OH2Hub) say they will support a West Virginia-led initiative to create a regional hydrogen hub funded by matching grants from the U.S. Department of Energy.

Battelle, an independent research institute headquartered in Ohio, which had initially advised OH2Hub, is expected to file the initial application for the West Virginia-centered Appalachian Regional Clean Hydrogen Hub (ARCH2) by the DOE’s Nov. 7 deadline.

DOE has $9.5 billion to help local industries and governments create as many as 10 regional hubs in which hydrogen would be produced close to where it would be used, largely by industry or in gas-fired power plants. The agency is expected to offer up to $2 billion in matching grants for each hydrogen hub.  

Sen. Shelley Moore Capito (R-W.Va.) and Battelle simultaneously announced the creation of ARCH2 on Sept. 29. Pittsburgh-based EQT, the nation’s largest producer of shale gas, is one of the principal backers of the effort.  

EQT CEO Toby Rice has campaigned for the creation of a hub focused on making hydrogen from natural gas, capturing the resulting carbon dioxide for injection into deep wells. The Infrastructure Investment and Jobs Act, which appropriated the funds for the creation of hydrogen hubs, calls for blue hydrogen production where natural gas is plentiful.   

Backers of the OH2Hub had proposed a blue hydrogen hub for Ohio because shale gas has been plentiful in the state and the state’s industries already produce 161,000 metric tons of hydrogen annually for immediate use, according to a study prepared by the Midwest Hydrogen Center of Excellence (MHCE).

MHCE, the Stark Area Regional Transit Authority (SARTA), Dominion Energy and Cleveland State University organized the OH2Hub effort.  

“We formed the Alliance to ensure that Ohio and Ohioans would have the opportunity to reap the economic and environmental benefits that will flow from the federal government’s commitment to and massive investment in the development of clean hydrogen technology,” SARTA CEO Kirt Conrad said in a statement. “We firmly believe ARCH2 will enable us to achieve that objective. …

“We will continue to serve as a point of contact and source of information about the Hub, recruit end users, work with Battelle on drafting the formal proposal that will be submitted to the DOE, encourage the state of Ohio to formally participate in ARCH2, urge the General Assembly to pass any legislation that may be needed to facilitate the development of the hub, and encourage the business community, labor organizations, local elected officials and the public to support the ARCH2 campaign,” Conrad said.

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RTOs, Utilities Push Back on Interconnection Deadlines, Penalties

RTOs, utilities and others told FERC Friday it should drop its proposal to penalize transmission providers for failing to meet interconnection study deadlines, while generation developers balked at the commission’s proposed “commercial readiness” provisions.

More than 130 companies, agencies and organizations filed comments in response to FERC’s June 16 Notice of Proposed Rulemaking (NOPR) to clear clogged interconnection queues and give generators more certainty on upgrade costs (RM22-14). (See FERC Proposes Interconnection Process Overhaul.)

Commenters generally supported the NOPR’s proposal to replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies.

The American Clean Power Association said the NOPR “contains many potentially valuable improvements to current interconnection policies,” calling for new rules to “provide predictability on the timetable for interconnection studies, as well as certainty on the upgrade costs that are identified through these studies.”

The Environmental Defense Fund said the changes were needed to address the “inequitable distribution of costs among interconnection customers based on the first-come, first served study process [and] delays created by the proposal and withdrawal of speculative projects [and] the lack of binding deadlines for transmission providers [and] the general failure of transmission providers to evaluate use of alternative transmission technologies.”

Calls for More Outreach

But there were disagreements on many of the details, and several commenters called for additional outreach before issuance of a final rule.

The Electric Power Supply Association said FERC may need to collect additional comment or convene a technical conference to work out the details. “Competitive generators strongly support a timely final rule from the commission to address long-plagued interconnection queues, but getting that rule as clear as possible saves time in the end for all stakeholders, including customers.”

CAISO said that “although many of the individual proposals in the NOPR are ripe for implementation, the sum of the NOPR would not achieve the commission’s goals and would instead slow study processes and increase backlogs.

“The CAISO strongly urges the commission to iterate with stakeholders further before issuing a final rule. At the very least the commission should issue a revised NOPR based on comments and should consider technical conferences on ISO/RTO-specific reforms, commercial readiness criteria and realistic study timelines.”

Regional Flexibility

The many state agencies that issued comments on the NOPR were broadly supportive of the changes to interconnection rules, which they said could help alleviate backlogs that are hurting their states. But they urged FERC not to interfere with existing regional efforts to make their processes more efficient.

“The imposition of overly prescriptive compliance obligations may disrupt and potentially dismantle many of the successful processes and practices already underway in the MISO region,” the Organization of MISO States wrote. “As such, we recommend that the commission permit transmission providers that are initiating their own stakeholder-supported interconnection reforms … to continue developing regionally appropriate solutions.”

“The commission should be sensitive and avoid creating additional burdens to those regions that have already adopted best practices,” MISO said. “Any proposed reform should be careful not to burden transmission providers by imposing non-essential or regionally inappropriate requirements to already-strained interconnection queue study processes and inadvertently increase the duration of the interconnection queue or risk of delays.”

“In discussing the need for queue reforms, the NOPR does not appear to recognize the different approach that New England has taken to interconnection-related network upgrade costs,” the New England States Committee on Electricity wrote. ISO-NE also asked the commission to avoid a “prescriptive” final rule.

The Edison Electric Institute also called for flexibility. “For example, FERC should allow transmission providers to develop the technical details for cluster studies, including how clusters may be split into subgroups of interconnection customers based on areas of geographic and electrical relevance,” EEI said.

“To the extent these ongoing efforts appear likely to accomplish the Commission’s goals of expediting the interconnection process, WIRES believes the commission should accommodate these efforts rather than slow down or preempt these initiatives by enforcing standardization with the proposed pro forma” interconnection agreements, the trade group WIRES said.

“Several of the NOPR’s proposals could harm existing interconnection processes and could specifically harm the NYISO processes that are working well to integrate the significant amounts of new clean energy resources required to attain the requirements of New York’s ambitious climate change legislation,” said the New York Transmission Owners, a comment that was echoed by NYISO.

PJM, which filed its own interconnection overhaul days before the NOPR, said the commission should allow it to complete its transition period before being required to comply with a final rule. (See PJM Files Interconnection Proposal with FERC.)

The PJM Transmission Owners opposed the commission’s proposal to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade. “The NOPR proposal for allocation of network upgrade costs should not be mandatory and regions should have the flexibility to determine just and reasonable approaches for cost allocation,” they said.

Proving Commercial Readiness

There was wide support for measures to discourage speculative projects from entering interconnection queues, with EEI saying, “The reforms that the commission has proposed involving study deposit frameworks, site control requirements and commercial readiness demonstrations are important tools to help cut down on speculative projects, increase certainty and reduce queue backlog.”

But numerous parties challenged FERC’s proposal to use finalized purchase power agreements as evidence of commercial readiness.

“Independent power producers would be challenged to enter into binding contractual sale obligations without having any reasonable certainty into their final interconnection costs,” the Solar Energy Industries Association said. “SEIA believes the final rule should allow developers to demonstrate commercial readiness through means other than firm contractual sale contracts or financial deposits. Commercial readiness should be evaluated based on the totality of circumstances, and should be required later in the process, so to avoid injecting uncertainty into the interconnection process.”

Vistra said requiring a demonstration of commercial readiness to proceed in the interconnection process “ignores the reality of competitive solicitations and unduly discriminates in favor of self-build options.”

Invenergy also opposed the commercial readiness requirements. “Interconnection customers will already be subject to other requirements that are far more indicative of ‘readiness,’ such as the increased site control requirement to enter the queue and withdrawal penalties under the new rules,” it said. “This additional ‘readiness’ proposal is unnecessary. Moreover, the focus on having a power purchase agreement (PPA) term sheet or contract to simply enter the queue ignores the commercial reality that independent developers do not typically have an off-taker so early in the process.”

EDF Renewables said FERC should increase study deposits and other capital requirements to discourage “overly speculative high-risk projects and project spamming” rather than relying on PPAs.

EEI said that allowing interconnection customers to provide financial security in lieu of meeting milestones or readiness requirements “can be used as a loophole for speculative projects to proceed well into the interconnection process,” potentially leading to restudies and delays.

Penalties, Deadlines

FERC also received strong opposition to its proposal to replace the current “reasonable efforts” standard for transmission providers and impose penalties for failing to meet study deadlines.

The ISO/RTO Council said although it understood the commission’s intent, “the proposal overlooks the reality that the RTOs/ISOs and their transmission owners have no control over the size of their respective interconnection queues and limited control over the quality of the submittals.”

It said the proposal would deprive transmission providers of their due process rights and introduce “a more litigious relationship among the parties.”

“Study deadlines must consider the scope, complexity and uniqueness of each such interconnection,” the New York TOs said. “Rather than allowing sufficient time to develop optimized interconnection studies, TSPs and TOs will be incentivized to rush or abbreviate the needed study effort to avoid running afoul of such deadlines and penalties, potentially leading to less optimal studies.”

The TOs said interconnection delays are often caused by interconnection customers. “Moreover, such IC-driven delays are often intended to allow them to improve their projects, and removing that flexibility would harm ICs and the overall effectiveness of their respective projects,” they said.

“Proposals such as automatic penalties for study delays and blanket elimination of the reasonable efforts standard will not help transmission providers manage the present overwhelming queue volume because they do not get to the root of the delays,” PJM said. “The commission’s proposed penalties may compromise reliability by forcing transmission providers to prioritize speed over accuracy.”

As an alternative, PJM proposed setting “tolerance bands for delays” and focusing on process improvement reporting to the commission, “with penalties potentially established after due process, based on misfeasance or malfeasance by the transmission provider in carrying out the specific process improvements.”

CAISO also opposed the proposed deadlines, saying “many of the NOPR’s proposed reforms are based solely on the tariffs of single utilities operating in a single state. Such utilities enjoy unique advantages because they can be both the generation off-taker and the transmission provider conducting the interconnection studies, and they have a single local regulatory authority over procurement. … The vast majority of commission jurisdictional interconnections occur in ISOs/RTOs where the off-taker and transmission provider are not only different, but may not even be in the same state. Many of the commission’s proposed reforms fail to recognize that the ISO/RTO may be the ‘transmission provider,’ but it depends on the actual transmission owners to perform study work.”

State officials expressed concerns that the penalties could ultimately be passed on to ratepayers.

“The record does not appear to support the position that fines will materially aid in reducing the interconnection backlog,” wrote a coalition of 13 East Coast state agencies, made up largely of attorneys general and state consumer advocates.

The Transmission Access Policy Study Group (TAPS), an association of transmission-dependent utilities in 35 states, expressed the same concern.

While TAPS recognized that FERC allows penalties imposed by NERC or regional entities for violation of reliability standards to be passed through in this manner, the organization argued that this situation is fundamentally different.

“The money collected from RTO ratepayers is used to offset the costs of operation of NERC or the relevant [RE]. … In contrast, the NOPR’s proposed study delay penalties will be remitted to specific interconnection customers, which may have no commitment to use these payments to offset costs to any consumers, much less ratepayers bearing those costs,” TAPS said.

A group of environmental organizations dubbed the Public Interest Organizations cited data from the Lawrence Berkely National Laboratory that they said showed that queue withdrawal rates have been consistent over the last 10 years, suggesting that the fear of speculative projects is misplaced. As a result, the commenters said that FERC’s contemplated queue withdrawal penalties are probably unwarranted. They suggested that the commission instead “emphasize the information sharing and process improvement aspects of the reforms over the aspects that introduce barriers to applications.”

Google expressed fear that the commission’s proposals “risk providing an advantage to utility development over independent power producer (IPP) development.” Google urged FERC to adopt a “holistic approach” that balances the readiness requirements, study deposits and withdrawal penalties in order to avoid “undermining the vibrant IPP sector.”

Acciona Energy, Copenhagen Infrastructure, Hecate Energy, Leeward Renewable Energy Development, and Tri Global Energy — filing jointly as the Affected Interconnection Customers — called for expanding the list of indicators of commercial readiness and granting interconnection customers “the unilateral right to retain preapproved outside consultants … if the transmission provider or transmission owner is unable to complete the necessary interconnection studies on time.”

Informational Studies, GETs

PJM and its TOs joined SPP and SEIA in opposition to proposed “informational” interconnection studies, saying it would provide information of limited value while taxing limited RTO resources.

SPP opposed the proposal “due to its past experiences in offering such a study and based on feedback received from its interconnection customers,” saying its feasibility and preliminary impact studies “did not provide results that could be relied on in making business decisions.”

Some, including the MISO TOs, also opposed a provision that would require transmission providers to consider “alternative transmission solutions” if requested by an interconnection customer.

The WATT Coalition, a trade association that promotes deployment of grid-enhancing technologies (GETs), supported the requirement but said it should be an “opt-out” rather than an “opt-in” rule, saying “advanced transmission technologies should be considered as a routine matter in interconnection processes in all regions.”

The Clean Energy Buyers Association warned that FERC’s suggestion of allowing interconnection customers to submit up to five informational study requests at a time could bog down “already over-burdened transmission provider resources and interconnection queues.” The group said that transmission providers should be allowed to establish windows of time each year to submit such requests.

More Please

A few commenters asked the commission to go beyond the proposals in the NOPR.

“Reforms to participant funding rules are also critical to any meaningful interconnection reforms,” Invenergy said. “Similarly, the commission needs to address the current inconsistency between generator interconnection and transmission planning studies, and develop pro forma procedures for HVDC transmission interconnection so development can move forward.”

Anbaric Development Partners asked the commission to draft a rule ordering ISOs and RTOs “to remove tariff barriers to the development of planned transmission or transmission-first projects,” saying the commission “already has before it a more than adequate record on which to justify this relief.”

The Electricity Consumers Resource Council, which represents large industrial consumers, asked FERC to add an independent transmission monitor to the NOPR “to ensure that there is coordination among the interconnection process and the transmission planning process.”

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NJ BPU Approves Waivers for 26 Residential Solar Projects

The New Jersey Board of Public Utilities (BPU) on Wednesday granted waivers of rules governing its new solar incentive program to 26 residential projects in a sign of the agency’s strategy as the state struggles to reach its ambitious goals.

The board granted waivers to seven projects on which developers had begun construction — and to seven that had begun operating — before the program opened. It gave waivers to another 12 projects with more capacity than is allowed under the program.

The move comes as the program under which the incentives were awarded, known as the Successor Solar Incentive Program (SuSi), which the BPU created in July 2021, has faced criticism. The incentives are about half the size of those in the previous program, which critics have said are too small and insufficient to stimulate the amount of new solar needed in the state. (See NJ Sees Solar Growth in Reduced Incentives.)

BPU staff told commissioners that the rules preventing the program from awarding incentives to projects that are already under construction or operating were designed to ensure that incentives go only to proposed projects that need subsidies to be brought to fruition, Scott Hunter, the BPU’s manager of the Office of Clean Energy, said in outlining staff’s recommendations. The limit on project overcapacity aims to create clearly defined eligibility standards and ensure that the “limited block” of power capacity set aside for the program is not oversubscribed, he said.

In granting the waivers, the BPU said many of the projects would not be successful without incentives.

Speaking before the 5-0 vote to approve the waivers, BPU President Joseph Fiordaliso said they don’t create a precedent for the future.

“We can never tie the board in a position that it has no alternative,” he said. “Because every case is unique in its own way. And we have to have that flexibility in order to look at each case individually, to determine what’s in the best interest of the citizens of the state of New Jersey.”

Future Implications

The board said in its order that the waivers were warranted in part to overcome the turbulence surrounding the state’s incentive programs, which have changed twice in the last three years, creating the “consequent potential for confusion among solar market participants.”

It also said the extra capacity from the 12 projects, totaling about 30 kW, will not “place the residential market segment megawatt allocation in jeopardy.” That’s because only about half of the 150 MW set aside for the segment has been allocated, according to the board, which predicted that the capacity would be fully subscribed by January.

“The ADI [Administratively Determined Incentives] program is still relatively new, and the megawatt caps included in this program did not previously exist,” the board explained. “While prior programs required registrants to notify staff if installed capacity exceeded what had been approved, incentives have not to date been denied for the excess capacity.”

But the order added that BPU has already put on hold another 14 projects that would create larger capacity than is allowed under the program rules. Those rules state that a project can be no more than 10% or 25 kW (whichever is smaller) greater than the approved size. “Staff is concerned about the implications” of granting waivers and the possibility that it will encourage project developers to develop larger-than-approved projects in the future, the order said.

Commissioner Dianne Solomon said that it “is important that we are not tying ourselves into a blanket waiver under any conditions.”

“There is an acknowledgement that these are new rules; it takes a while for everybody to get on board and understand their requirements,” she said. “We accept that. But I think it is important that we make it clear what our intentions are: that the rules be followed.”

Power Surge

New Jersey had 4.14 GW installed solar capacity as of the end of August, according to the latest figures available, and the state is seeking to reach 17.2 GW by 2035 as part of Gov. Phil Murphy’s goal of 100% clean energy by 2050. Murphy wants the solar sector to generate 32 GW by 2050. Murphy in 2021 signed the Solar Act of 2021, which called on the state to add 3,750 MW of new solar by 2026.

BPU data on solar installations suggest that the state may reach its goal of 5.2 GW by 2025 but may find it difficult to reach the 2030 goal of 12.2 GW.

Since the start of the year, the state has added about 345 MW. If it continues at that rate, it would add nearly 520 MW this, surpassing the previous record of about 449.8 MW in 2019.

Not all of that surge is from a strengthening solar sector; part stems from the reshaping of the state’s solar incentive programs. For more than a decade, the state offered relatively generous incentives under the Solar Renewable Energy Certificate program that paid about $250/MWh. The program was cut in 2020, in part because of concerns that it was too generous, and replaced with the temporary, lower incentives of the Transition Incentive (TI) Program, which ranged from about $90 to $150/MWh.

The BPU replaced that program, which was created as a short-term stop gap, with SuSi, which provided a two-pronged approach. One half, the ADI program, offered even lower incentives, from $70 to $100 depending on the project. The second prong, the Competitive Solar Incentive (CSI) program, will set the incentives of solar projects larger than 5 MW through a competitive solicitation. The final rules are expected to be released later this year.

One impact of the shifting incentive terrain is that solar developers, seeing that the BPU expected to reduce incentives, scrambled to submit projects in the TI Program before it ended. That created a surge of projects, with 1.6 GW in the pipeline at the start of the year, three times as much as a year earlier. (See NJ Solar Pipeline Surges While Installations Drop.)

That pipeline capacity has since dropped to 1.05 GW as of August, as some of it has begun operating, and it is unclear how long the high level of monthly installations will continue.

Critics of the new incentive program, among them the International Brotherhood of Electrical Workers Local 102 and the New Jersey Utility Scale Solar Association, argue that the incentives are too low and, as a result, applications to the BPU for new solar projects have fallen. Both want the legislature to enact a pending bill, S2732, that would extend the deadlines by which projects must be finished in the TI Program, allowing those that are delayed to be completed with the higher incentive.

The BPU, however, denied some TI extension requests in August, saying they have to balance the demands of solar developers with the need to protect ratepayers from rising incentive costs. (See NJ BPU Denies Deadline Extensions for Solar Project Incentives.)