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November 15, 2024

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PJM MRC/MC Briefs: June 22, 2023

MRC Endorses IROL-CIP Cost Recovery

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed a proposal to create a cost-of-service payment structure for generators that require upgrades following being designated critical to the derivation of an interconnected reliability operating limit (IROL) under NERC’s critical infrastructure protection (CIP) standards. (See “PJM, Monitor Review IROL-CIP Proposals,” PJM MRC/MC Briefs: May 31, 2023.)

PJM’s Darrell Frogg previously told the committee that the proposal would function similarly to PJM’s existing black start cost-recovery mechanism, with generators submitting costs to the RTO and Monitor to review, and reviews collected through charges to market participants.

Supporters during the Operating Committee discussions on the proposal argued that having a facility declared critical by NERC and required to make reliability upgrades is outside of their control, can carry significant costs and is unpredictable. The OC endorsed the PJM proposal on March 9 with 89% support, while a competing proposal from the Independent Market Monitor received 11%. (See PJM OC Briefs: March 9, 2023.)

Susan Bruce, representing the PJM Industrial Customer Coalition (ICC), questioned if there are any cost minimization functions taken into consideration and what costs PJM can share with stakeholders regarding IROL-CIP expenses.

Frogg said security concerns limit how transparent they can be about specific costs, but there are oversight mechanisms in place and cost estimates of IROL-CIP upgrades in general can be shared, similar to data sharing around black start costs.

Independent Market Monitor Joe Bowring said the definition of which resources can be designated as critical is vague and argued that it’s a slippery slope to create new cost-of-service structures, rather than putting the costs in the markets.

“This is not like black start; it’s opening a whole new opportunity to non-market cost-of-service recovery services,” he said.

“PJM operates markets. PJM is not a cost-of-service regulator. These costs are part of the cost of doing business as a generator in PJM markets. Generators do not offer to share excess revenues when regulatory changes result in more revenues rather than more costs. This proposal is inconsistent with the PJM market design,” he said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said advocates appreciate Bowring’s efforts to find a market solution and believe the question of whether this should be a cost of service is best addressed at FERC. Several advocates abstained from Thursday’s acclamation vote on the proposal.

“There’s always a concern, I think a growing concern in some respects, about cost-of-service mechanisms at the PJM level,” he said.

Dominion’s Jim Davis said ensuring that generators can recover their costs avoids putting operators in the positions of considering retirement after being found critical due to the cost of making the required upgrades.

Frogg said costs will be recovered over 12 months and only those upgrades that are required to comply with CIP standards and would not be made had the facility not been designated critical would be recoverable under the proposal.

Craig Glazer, PJM vice president of federal government policy, said the proposal is consistent with other formula rates approved by FERC and implemented by the RTO. While PJM determines which facilities are critical and which upgrades are legitimate, it must follow the formula approved by the commission.

“It’s not like whatever you believe is reasonable you go with,” he said.

Bowring responded that the fact that it’s possible to define a cost-recovery mechanism is not a reason to do so. He said the proposal raises the possibility that there will be proposals for more cost-of-service recovery mechanisms in the markets, undermining the fundamentals of the PJM market design.

PJM Gives Date for Winter Storm Elliott Presentation

A detailed report on the impact the December 2022 winter storm had on PJM’s operations and generator performance during the event will be released on July 17, PJM Vice President of Market Design and Economics Adam Keech told the MRC. A workshop for stakeholders to discuss the report has been scheduled for July 25, with the aim of giving stakeholders time to digest the document.

“Right now, the paper is fairly hefty, so it may take an amount of time to get through it,” Keech said.

PJM provided a preview of the report’s findings during a May 17 critical issue fast path (CIFP) process meeting, a forum that was in part convened in response to the storm’s impact. (See PJM Presents Lessons Learned from Elliott, More CIFP Presentations.)

During that meeting, PJM’s Glen Boyle said Elliott was the latest winter storm demonstrating what the RTO has concluded is a shift in reliability risks toward the winter, rather than its longtime assumption that risk correlated with summer load peaks.

The analysis has found that market participants require additional education regarding performance assessment intervals (PAIs) and the penalties they carry for generators underperforming during an emergency. It also found instances where the penalties were not aligned with dispatch basepoints due to resources’ obligations not taking their specific characteristics into account.

Boyle laid out a series of recommendations that PJM had reached as a result of the analysis at that point, including an overhaul of capacity market incentives, re-evaluating whether energy efficiency and demand response resources have performed in a way that matches their expected reliability contributions and investigation of poor performance of non-retail, behind-the-meter generation.

Stakeholders Approve Tariff Clarification on Smooth Supply Curves

The MRC endorsed proposed tariff changes aimed at clarifying that smooth supply curves will only be published for Base Residual Auction (BRA) results and not for Incremental Auctions (IAs). (See “First Read on Smooth Supply Curve Quick Fix,” PJM MIC Briefs: April. 12, 2023.)

PJM’s Skyler Marzewski said the new language consists of adding “for each Base Residual Auction” to a paragraph in Attachment DD section 5.11(e) pertaining to how the supply curve will be graphed after the auction.

Road Path for CAPSTF Discussed

The Clean Attribute Procurement Senior Task Force (CAPSTF) is on hiatus until September after more than 90% of stakeholders participating indicated that the group should suspend discussions until the CIFP has completed its work on drafting changes to the capacity market because of overlap in the two groups’ deliberations. A second vote also found that none of the three conceptual designs drafted by the task force reached 50% support.

Scott Baker, PJM’s facilitator for the task force, said the group will reconvene in September to determine if it should continue working toward market-design changes based on the final product created through the CIFP process or if the CAPSTF should be sunset.

He said Package A would create a forward clean energy market with a PJM renewable energy certificate and a PJM clean energy attribute certificate differentiated on the eligible technologies. Package B would have a third product, a clean capacity certificate. The certificates in Package A would be unbundled from energy, while the added certificate under Package B would be unbundled from capacity.

Package C would create a two-auction system, with a state attributes procurement auction (SAPA) that would provide the locational marginal reliability value of participating clean resources and a minimum reliability attributes auction in which PJM would procure enough capacity to satisfy locational reliability needs netted against the impact of SAPA resources’ impact on load.

Calpine’s David “Scarp” Scarpignato said the company supports the clean energy transition but believes the capacity market is not the best place for market-design changes to be made with the goal of incentivizing new renewable generation.

“There might be better ways through the energy market or maybe bilaterals to get a more effective transition to clean energy,” he said.

Ken Foladare of the Tangibl Group said the CAPSTF has engaged in fruitful discussion, but agrees the CIFP process is likely to yield significant changes to the capacity market and its work should be completed before the task force continues drafting design packages.

Constellation’s Adrien Ford noted that the task force’s vote to go on hiatus had a significant number of abstentions and suggested the reason could be that it was an advisory vote on how the group should best direct its work. She said the company supports Package A and hopes that the work on finalizing the proposal can continue.

PAI Notifications to Include More Information

PJM’s Chris Pilong said the RTO plans to include information about the proposed revisions to conditions under which a PAI can be declared in any future notifications sent out when an interval begins. Should a PAI be called in the “limbo period” before FERC rules on PJM’s filing, email notifications will include the proposed language and the impact it could have on settlements if FERC were to accept the change. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

If the order were to partially approve the filing or a deficiency notice issued prior to a PAI being called, notifications would include information about what changes to the proposal are required.

If FERC were to approve the filing, software changes would be developed to allow more precise notifications to be sent out and information would include what changes have been made. Notifications would go out to all stakeholders subscribed to email lists for the standing committees.

Vitol’s Jason Barker said he’s concerned about the potential for notifications to be sent out for false positives or when the criteria for a PAI have not all been met, adding that any actions PJM can take to give a more assertive signal to market participants are welcome.

Old Dominion Electric Cooperative’s Mike Cocco urged PJM to develop a way for data about emergency conditions to be pushed to members, rather than require them to go to PJM’s Data Monitor portal to monitor for any changes.­­

Members Committee

State Advocates Concerned About Rising Transmission Costs

Speaking to the Members Committee Thursday, Poulos said consumer advocates are concerned about the rising cost of transmission for end customers and the lack of market-driven ways of containing costs.

“It is now about 28% of the bill for wholesale-cost customers,” he said.

Exelon’s Alex Stern said transmission development is mainly driven by state and federal policy, rather than markets. Grid reliability concerns have driven investments for decades and the challenges presented by the clean energy transition have only exacerbated the issue.

“A lot of what we’re seeing in real time as far as transmission investment is driven by regulatory signals and from my perspective that’s how it should be. Transmission owners will continue to discharge their obligation to ensure grid reliability is preserved. The regulators need to keep doing the job on their end as well and if they feel the grid is reliable enough or if they feel the transition is happening too fast, then they need to send those signals as well,” he said.

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PJM Continues CIFP Discussion of Seasonal Capacity Market Proposal

PJM last week continued outlining its proposal to redesign the capacity market to address resource adequacy and reliability concerns through the Critical Issue Fast Path (CIFP) process.

The June 21 presentation followed a June 14 CIFP meeting initiating the third stage of the CIFP process, in which PJM and stakeholders will finalize their proposals. Both stage-three meetings have been devoted solely to PJM’s proposal, with additional time scheduled to continue the presentation this Wednesday. (See PJM Adds Seasonal Capacity to Stage 3 of CIFP Proposal.)

Both meetings were dominated by discussion of PJM’s proposition to bifurcate the capacity market into summer and winter products, which it argues would allow the markets to address a shift in risk toward winter storms, rather than the historical expectation that risk coincides with the peak loads that typically fall in the summer.

PJM Senior Director of Economics Walter Graf said resources could submit offers to participate in either season and could clear in both, one or neither. Resources with costs to operate that may not be recovered by clearing in just one season would be able to indicate a minimum price, which would prevent them from being committed if they cleared in only one season and would not cover their costs at the price the other season’s auction reached. Most resources today have capacity value in both seasons, Graf said, and would have both annual and seasonal costs.

“There are certainly resources today that are mitigated to offer at zero. Those resources would probably also in this construct be mitigated to have a zero-offer component,” he said.

Kevin Kilgallen, of Avangrid Renewables, said each season carries its own risks for generators as well, creating a need for a season-specific capacity performance quantified risk component to fully represent those liabilities.

Once resources clear the seasonal auctions, an adjustment factor would be used to align the results with the annual variable resource requirement (VRR) curve. The summer and winter capacity price would be linked and scaled up or down until it matched the price on the VRR curve with the corresponding amount of capacity procured.

PJM’s Skyler Marzewski said the advantage of retaining an annual is that the new market structure would be built around components already approved by FERC. Graf said that under “blue sky” conditions, without the constraints of the CIFP timeline, avoiding this additional step would be ideal.

“What are the fewest steps we can take to make a seasonal approach with what we already have,” he said, describing PJM’s approach to drafting the new model.

Kilgallen said if PJM’s preference is to move entirely to seasonal auctions with their own demand curves, it should do so rather than trying to use adjustments to get back to the current annual VRR curve.

“If the seasonal demand curves are the way to go, let’s just go there and accept it,” he said.

Calpine’s Matt Barmack said if the summer clearing price is low, reflecting PJM’s belief that risk is now concentrated in the winter, resources may struggle to clear in that auction and cover their full annual costs.

Graf said co-optimizing the seasonal capacity prices allows the rate at which each auction clears to also reflect any costs generators may incur that bleed into other seasons. That’s also in part why PJM decided to seek a seasonal model with two auctions, rather than adding more granularity, he said.

The shift toward winter risk is in part a result of PJM’s proposal to use an expected unserved energy (EUE) model for its reliability analysis instead of its status quo loss of load expectation (LOLE). During the May 30 CIFP meeting, PJM shared preliminary analysis of how the EUE model — which aims to capture the depth and breadth of outages, rather than a count of the number of incidents — could change its thinking on what periods have the highest risk. (See “PJM Presents Risk Modeling Analysis,” PJM Stakeholders Complete 2nd Phase of CIFP.)

The analysis suggests that 96% of the risk is concentrated in the winter under the EUE model, compared to 78% under LOLE. The increase in winter risk also reflects a proposal to use a longer lookback for weather data to capture the impact of rarer weather events.

PJM’s presentation of its proposal is to continue Wednesday, with discussion of a potential model for reliability risk assessment and changes to accreditation, particularly pertaining to the effective load carrying capability construct. The Independent Market Monitor and Leeward Energy also are set to make presentations.

PJM Director of Stakeholder Affairs Dave Anders said additional stage three CIFP meetings will likely be required before the stage-four meeting scheduled for August, when stakeholders will vote on the proposals.

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MISO Stakeholder Activists Propose Equity Principles

MADISON, Wis. — MISO stakeholders from the environmental and consumer-advocate realms are on a mission to make the grid operator’s transmission planning more equitable in nature and accessible to the public.

Leading the charge is Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, who said there’s a lack of accessibility within MISO for individual ratepayers to make their opinions heard on grid decisions that affect them.

During a public comment period at MISO Board Week held in Madison in mid-June, Cappel-Vickery introduced a set of equitable grid principles she wrote with a group of 25 scientists and activists from throughout the MISO footprint in the hope that MISO will adopt some or all of them in its transmission planning.

The principles call on MISO to prioritize renewable energy, climate resilience, indigenous rights, an environmentally conscious sourcing of infrastructure materials, worker protections, making meetings more user-friendly and communicating with and addressing concerns of impacted communities during system planning.

Cappel-Vickery told the MISO Board of Directors that transmission planning is “becoming increasingly public,” as evidenced by a recent article in the New York Times that emphasized that the clean energy transition is dependent on major transmission construction.

She asked the MISO Board of Directors to consider how the equity principles can be implemented into the RTO’s transmission planning and the Board of Directors governance.

Authors of the document also include members of the Union of Concerned Scientists, the Environmental Law and Policy Center, Vote Solar, Healthy Gulf and the Center for Earth, Energy, and Democracy, among others. The representatives began connecting last summer to devise the principles.

Authors of the principles call themselves the Equitable Grid Cohort and met in New Orleans in the fall to discuss how transmission investment decisions can be made more equitable and with more community input. | Colin Byers, Union of Concerned Scientists

“MISO and other RTOs are too heavily influenced by the interests of incumbent electricity industry players. Impacted communities and the general public are often marginalized in grid infrastructure decision making at the RTO level…Ultimately, decisions about the purpose and siting of billions of dollars in grid infrastructure are made with little public accountability,” the groups wrote in the equity  principles. They said MISO and state utility commissions are “generally inaccessible to the public and to impacted communities.”

“There are a lot of people getting more knowledgeable about the levers they can pull to make changes. We only have things to gain from feeling more empowered about the system that impacts all of our lives,” Cappel-Vickery said in an interview with RTO Insider.

Most of MISO’s stakeholder meetings are open to the public, but Cappel-Vickery said the learning curve to understand what’s being talked about is daunting.

She said MISO hosting some public meetings free of acronyms and pared-down technical speak would go a long way in making MISO more accessible to the public. She also said MISO can provide more accessible education so that the public understands the important work that it provides.

“It’s a lot of acronyms. RTO language isn’t just engineers. It’s also economists, public service commission staff, politicians. It’s like a convergence of four foreign languages,” she said. “When the equity conversation comes up, I think people get uneasy. And it’s hard. But one thing that is completely free is saying what you mean without acronyms. … I don’t think folks need to understand every nitty-gritty detail to understand that they want transmission to deliver cleaner and more reliable energy.”

Cappel-Vickery said when she explains the grid’s innerworkings, she often makes parallels to the highway system enabling trucks to deliver food to grocery stores.

Cappel-Vickery said the principles are designed to be iterative, and MISO could customize them.

“This is something that MISO can look at and say, ‘We can achieve four of these but maybe we can’t adopt these others right now.’ Even if they could only adopt some components of the principles, it would go far to show that MISO is taking this seriously,” she said.

Cappel-Vickery said the principles shouldn’t be construed as rebuke of MISO, either.

“From my work and perspective, MISO is not a bad guy. MISO does critical work, and we rely on their brilliant staff to keep the lights on,” she said.

Cappel-Vickery said MISO might approach the conversation by asking the authors of the grid principles to speak to staff and stakeholders at one of its public meetings. She said she realizes that equity planning isn’t something that RTOs have historically engaged in.

“Just because we haven’t done it before doesn’t mean we can’t do it now,” she said. “We just think there are ways planning could be a little bit better and more inclusive.”

Co-author and Union of Concerned Scientists Senior Energy Analyst Sam Gomberg said the set of equity principles “provide clear guidance to MISO regarding the future we need to be driving towards.”

“MISO is in the midst of an extraordinary transition to clean energy, and the decisions made at MISO affect every community located in its footprint. It’s critical to get it right,” he said in an emailed statement to RTO Insider. “…As MISO and its member utilities embark on an unprecedented build out of the transmission system to enable clean energy, communities will be asked to support these investments and host this infrastructure. These principles inform all of us about what needs to happen to garner their support and to be successful in our collective efforts to build an equitable, just, and clean energy future.”

Cappel-Vickery pointed out that MISO’s quarterly board meetings occur in the middle of a work week “at a time when anyone not expressly hired to do this is in working hours.” She said MISO might allow for public comments that aren’t reliant on attendance. MISO could dedicate an inbox to collecting emailed comments and could publish them or read them to board members during open sessions, she said.

She said that could lead to a resident of Louisiana, for example, telling MISO they’d like a more interconnected MISO South even if they aren’t available to travel or call in.

“That’s something that isn’t going to be a huge lift. We hear from MISO that they’re overburdened, that they’re experiencing labor shortages, but this is doable,” she said.

She also said MISO’s Consumer Advocate Sector could “activate” new members to be a mouthpiece for the public during meetings.

Cappel-Vickery suggested MISO embrace the stance that climate change is real from an apolitical, scientific perspective and should be planned for accordingly. She said it’s possible for MISO to discuss grid resilience in a way that expressly includes climate change.

“The way that it’s spoken about now, it seems like this opt-in. It doesn’t sound like it’s definitive, that this is something we need to address,” she said. “Here in south Louisiana, whether you believe in climate change or not, we’re experiencing storms that are more severe and more frequent.”

More Lines Equal Equity in MISO South

Cappel-Vickery, a New Orleans resident, said while she wants the equity in planning principles applied to MISO Midwest and MISO South alike, they would be particularly beneficial in MISO South.

Cappel-Vickery said in her experience, many MISO South residents welcome the idea of transmission expansion, viewing it as crucial to avoid prolonged outages during heatwaves or after hurricanes. She said the importance of equity planning was never more crystallized than in the aftermath of Hurricane Ida in 2021.

“People lost their lives after that storm. We don’t see transmission as being inherently bad at all,” she said.

She also said soaring summertime temperatures are cause for more intensive planning.

“I have no recollections in my childhood of experiencing 115-degree heat indexes. And now we have them multiple times per year. It seems imperative to include climate change modeling when they’re talking about reliability,” she said.

Cappel-Vickery said she shares concerns that Entergy’s outsized local reliability spending in the 2023 Transmission Expansion Plan could negate the need for larger, regional transmission and could lead to a “really skimpy” third cycle of MISO’s long-range transmission plan (LRTP) portfolio, which will be the first to contemplate MISO South subregional needs. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

“There are a lot of questions around Entergy’s proposals. And we’re not OK with the cost burden falling completely on ratepayers,” Cappel-Vickery said of a regional-versus-local cost allocation. “Tranche 3 and Tranche 4 could hold incredible potential for ratepayers in MISO South. From our organizational standpoint, a worst-case scenario is we keep building more generation and never expand transmission.”

MISO: Onus is on Members and State Officials

MISO said it “acknowledges the importance of concepts such as those outlined in the equitable grid principles” but said it is limited in what it can do as it doesn’t own grid assets.

“We support our members’ goals as they address clean energy, siting and overall investment in electricity infrastructure. As MISO does not own, site or construct electricity infrastructure, our members and state regulators are a more appropriate venue to assess and appropriately address these matters. MISO’s role is to understand the impacts of our members’ plans as it relates to existing energy policies and provide insight on how to reliably implement their goals,” MISO spokesperson Brandon Morris said in an emailed statement to RTO Insider.

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Siemens Gamesa Quality Control Problems Growing Worse

Siemens Energy said last week that quality-control problems with components of certain Siemens Gamesa onshore wind turbines are worse than previously believed.

The parent company on Thursday withdrew its profit guidance for fiscal year 2023 and said costs incurred correcting the situation will likely exceed a billion euros.

“The fact that we have identified more quality problems marks a significant setback for us,” Siemens Energy CEO Christian Bruch told financial analysts in a conference call Friday. “This setback is more severe than I thought possible.”

The revenue guidance issued May 15 — calling for a 10 to 12% increase over fiscal 2022 — remains in place.

Siemens Energy stock tanked in subsequent trading, closing 37.3% lower Friday on the Xetra market.

Siemens Gamesa is a leading company in the wind power industry, with more than 130 GW of nameplate capacity installed worldwide. Its 11 GW offshore turbines will equip what is likely to be the first utility-scale wind project to come online in U.S. waters: South Fork Wind.

But it has seen a rising defect rate in its wind power products, as have competitors General Electric and Vestas.

During Friday’s call, Bruch said the problems appear to be concentrated in select components and with a few important suppliers. The billion-euro price tag, he said, is only an initial assessment and does not include mitigation measures.

Bruch touched on other problems in the company’s wind power product line: Productivity is not improving as expected, and challenges persist in the offshore wind manufacturing ramp-up.

Corporate culture at Siemens Gamesa also is a problem, Bruch said: “Too much has been swept under the carpet.”

He said Siemens Energy will soon own 100% of Siemens Gamesa, which will aid its efforts to put the house in order, but Siemens Gamesa will incur heavy losses this year.

Further analysis is needed to fully understand the extent of the problems and their repercussions, Bruch said, and he expects to provide more details no later than Aug. 7, when the third-quarter financial report is due.

But he and Siemens Gamesa’s new CEO, Jochen Eickholt, were able to offer additional information during their Q&A with analysts Friday.

Bruch said some of the problems — such as degradation from increased vibration — will not manifest immediately, which makes it hard to calculate their eventual cost and impact.

“Some of the components show perhaps different behaviors over lifetime, and the lifetime sometimes extends 25 years,” Eickholt said. “In the end of the day, what’s going to happen in the next 20 years is not so easy to predict.”

The problems are mostly occurring in recent installations, Eickholt said, so the challenge is to model the lifetime of similar units using data from a limited number of failures.

Early results show a 15% to 30% failure rate, he said, but the company is trying to refine that estimate through better modeling.

One analyst asked why the profit guidance was issued in mid-May if it was going to be recalled only five weeks later: “What exactly are we dealing with in terms of culture here, and how confident are you that you have nothing else swept under the carpet?”

The failure rates have been increasing recently, Bruch said, and his understanding of the situation has evolved in that brief time.

“I would not relate this to five weeks ago.”

Another analyst said the industry’s earlier race-to-the-bottom strategy appears to be the basis of the quality-control problems being seen, and asked how the company could be sure this would not repeat as new products are launched and new suppliers qualified.

The practices of the past are not the basis for running the company today, Bruch said, yet it must cope with this legacy while building its future.

“That is something that is super-painful today, but it is not to be extrapolated going forward to say, that is the logic of the industry,” he said.

Friday’s call focused on the onshore product line, but the same problems have had an “absolutely disappointing” impact on the installed offshore fleet, Bruch said.

An analyst asked about the potential financial ramifications of this, as offshore turbines are much larger and much harder logistically to work with than their onshore cousins.

Bruch did not directly answer the question, saying instead that ramping up any industry sector comes with its challenges. (See Big Offshore Wind Plans Face Multiple Major Obstacles.)

He did say there needs to be “proper risk and reward balance in your business models” to help drive the energy transition and that Eickholt has been vocal about this.

The company will be selective about the projects it takes on, Bruch said, and that is reflected in the order intake.

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New York PSC Calls for More Transmission for Long Island OSW

ALBANY, N.Y. — The New York Public Service Commission on Thursday announced it is commissioning NYISO to focus its next Public Policy Transmission Needs process on facilitating the delivery of 6,000 MW of offshore wind generated off the Long Island coast to the New York City area (22-E-0633).

State law mandates that at least 9,000 MW of offshore nameplate capacity come onto the state’s grid by 2035. The PSC ordered the development of new transmission to accommodate these future resources by 2033.

A solicited proposal will be deemed complete if it includes all the facilities, equipment, and transmission or substation upgrades necessary to deliver the energy through Consolidated Edison’s local system. The project selected will also be required to obtain transmission siting approval and undergo a full environmental and community impact review.

The PSC’s call for another Zone J-to-K-based PPTN came just two days after the NYISO Board of Directors selected Propel NY Energy’s proposal to fulfill an earlier Long Island PPTN that will increase the island’s export capability by at least 3,000 MW and build three new 345-kV lines on the local transmission system. (See related story, NYISO Selects Propel Project for Long Island Transmission.)

“We conclude that this public policy requirement drives the need for additional transmission facilities, and in particular, we seek options for delivery of the output of offshore wind generating resources to New York City interconnection points,” PSC Chair Rory Christian said.

Fred Zalcman, director of the New York Offshore Wind Alliance, a consortium of wind developers, praised the PSC’s order, saying, “This week’s historic transmission decisions by New York policymakers offers a critical ‘one-two punch’ in getting clean and renewable energy online.

“New York’s transmission system was never designed to support the flow of power from offshore, and this week’s decisions demonstrate policymakers’ resolve to modernize New York’s grid and remove one of the biggest obstacles to offshore wind energy development.”

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ERCOT Board of Directors Briefs: June 19-20, 2023

AUSTIN, Texas — ERCOT said last week it is reviewing the electric-industry-related legislation that passed during the Texas Legislature’s recently completed biennial session to determine what changes are required and their effect on grid operations.

CEO Pablo Vegas told the Board of Directors Tuesday that the legislative session was “intense” given the number of electric-related bills that were taken up and the “disparate opinions on how to address really the core issues of market redesign.” He promised a full report in September.

The 88th Legislature saw 257 bills filed touching on energy, ERCOT or the Public Utility Commission. Two years ago, after the deadly 2021 winter storm that nearly took out the Texas grid, legislators filed 311 bills. In the four sessions before Winter Storm Uri, an average of 100 similar bills were filed.

“Our team is currently working on analyzing the effect of all the provisions that have passed in the legislature,” Vegas said. “We will be communicating more as we assess along with the [PUC] the best approach for complying with the new changes in legislation.”

A sunset bill (House Bill 1500) that maintains operations at ERCOT, the PUC and the Office of Public Utility for another six years included several market redesign elements. Chief among those were several provisions adding guardrails to the PUC’s proposed performance credit mechanism (PCM) that rewards generators with credits for reliable performance during a predetermined number of scarcity hours. (See Texas PUC Submits Reliability Plan to Legislature.)

The measure caps the net cost to the ERCOT market at $1 billion (less the cost of bridge solutions), adds penalties for generators that don’t meet performance obligations and requires that bridge solutions to the PCM be rolled back.

HB1500 also requires ERCOT to add an uncertainty ancillary service product called dispatchable reliability reserve service (DRRS). Based on historical variations in availability for each season, the DRRS’ criteria require participants to be online and dispatchable for less than two hours after being deployed and to run for at least four hours. The intent is to reduce ERCOT’s reliance on reliability unit commitments, which have soared under the grid operator’s conservative operations posture.

The ISO could also have to deal with Senate Bill 2627, which creates a low-interest loan program with $5 billion set aside by lawmakers for primarily new gas generation in ERCOT. Loans and completion bonuses would be disbursed through the Texas Energy Fund, which must first be approved by voters in November.

Board OKs 27% Increase in Admin Fee

The board accepted the Finance and Audit Committee’s recommendations to increase ERCOT’s system administration fee for the first time since 2016 and to approve the 2024-25 biennial budget.

The admin fee will be raised from $0.555/MWh to $0.710/MWh, a 27.9% increase. Much of that difference will be passed on by retailers to ratepayers. Consumer advocates don’t oppose the increase, saying it was long overdue and will help pay for the real-time co-optimization (RTC) project that is expected to save billions.

The budget will provide ERCOT with $424.03 million and $426.99 million in 2024 and 2025, respectively, for operating expenses, project spending and debt service obligations.

Both measures will be filed with the PUC for its approval.

According to a 2018 Independent Market Monitor report, the market tool would result in a $1.6 billion reduction in annual total energy costs, or about a $4/MWh price reduction. The report also found reliability would be improved by reduced overloading of transmission constraints and less use of the regulation-up ancillary service equating to $4.3 million. Another $400 million would have been saved by reducing congestion costs and ancillary service costs.

Staff told the Reliability and Markets (R&M) Committee June 19 that it will cost about $50 million to complete the RTC project, which was put on hold after the 2021 winter storm. They said RTC’s complex implementation has made it difficult to find the timing and resources for delivery, but that they are ready to resume work on July 1 with an eye on completing the project in 2026.

Most other grid operators already use the RTC tool, which dispatches energy and ancillary services every five minutes. ERCOT says RTC will produce energy from cheaper resources, with more expensive resources shifting to the ancillary market.

In discussing ERCOT’s technology stack with the R&M, Vegas said RTC and the PCM, “potentially,” are among the near-term major projects.

New Ancillary Service Deployed

Staff told the board that the ISO has added and deployed in June its first ancillary service in more than 20 years with ERCOT contingency reserve service (ECRS). The product provides the system with additional capacity that can ramp in 10 minutes to respond to short-term net load ramps.

Vegas said ECRS is necessary because load and generation are constantly changing because of daily load patterns and instantaneous load variation, changes in variable generation and units tripping offline.

ECRS procurements began June 10 with “minimal hiccups,” Vegas said. It was first deployed June 14, and then again June 16 and 18 for between five and 25 minutes in amounts between 200 and 600 MW. ERCOT procures about 2 GW of ECRS per hour at an average price of $25.26/MWh.

“It’s working exactly as we had hoped,” Vegas said. “It’s become a new tool in our suite of operational flexibility products. We’ve got a broader suite of tools now that we can use to help deal with changes in load changes in supply and to be able to respond very quickly to market conditions as they evolve.”

ERCOT Mulling Coming EPA Regs

ERCOT general counsel Chad Seely briefed the board on EPA’s Good Neighbor Plan, which requires nitrogen oxide emission reductions from power plants and industrial facilities, and four other pending regulations that could affect the state’s dispatchable resources.

Texas is among 23 states that, under the plan, must meet the Clean Air Act’s “good neighbor” requirements by reducing pollution that contributes to problems attaining and maintaining EPA’s health-based air quality standard for ground-level ozone in downwind states. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)

The plan was to be effective Aug. 4. Texas, after earlier being granted a stay of  EPA’s disapproval of its state implementation plan by the 5th U.S. Circuit Court of Appeals, filed a lawsuit June 7 with the same court that challenges the good neighbor plan.

“The EPA right now is coming out with a lot of rules over the near-term and long-term could have a significant impact on our dispatchable resources,” Seely told the board.

ERCOT’s Chad Seely briefs the Board of Directors on upcoming EPA regulations. | © RTO Insider LLC

He said EPA’s most significant rule is the proposed greenhouse gas rule that would require new carbon dioxide restrictions for some coal and gas units by 2030. Several parties have asked for an extension of the Aug. 4 comment deadline; Seely said he expects EPA to grant that request.

In the meantime, ERCOT is evaluating the reliability effect on the thermal generation fleet. Seely said the ISO is collaborating with the PUC, the Attorney General’s office, and the Texas Commission on Environmental Quality.

“But most importantly, we have to engage the generators to understand what the direct impact is,” Seely said. “They were very instrumental in giving us feedback that ultimately rolled into our assessments … so it’s critically important as we continue to move forward and evaluate these regulations that we have the partnership with the generators to continue to work with ERCOT. They are really in the best position to tell us what that overall impact is.”

Seely reminded the board and stakeholders that the greenhouse rule is still in the formal rulemaking process. He said while the final outcome is unknown, he does not see any obstacles “in the path of any generation facility.”

“We don’t know what challenges may occur” when the final rule is published, he said. “I assume every investor is looking at what the potential environmental restrictions will be going forward with these proposals.”

“If you’re an investor thinking about putting capital into a project like this, a rule like this causes regulatory uncertainty,” cautioned board Vice Chair Bill Flores. “I think it will be exceptionally damaging to potential construction of possible units. This is scary.”

Other proposed EPA regulations include:

  • The Texas Regional Haze Federal Implementation Plan that would establish new limits on sulfur dioxide and particulate matter emissions for a dozen primarily coal-fired generating units;
  • Revisions to the Mercury and Air Toxics Standards Rule that further restrict mercury and “filterable particulate matter” emissions from coal- and oil-fired generating units; and
  • A tailpipe rule that would further reduce greenhouse gas and other emissions from light, medium and heavy-duty vehicles.

Directors Approve 12 Rule Changes

The board unanimously approved 12 protocol and guide changes. Three measures, with dissenting votes during the stakeholder process, were approved separately, including a nodal protocol revision request (NPRR1169) that expands the qualifications for generation resource that may be a firm-fuel supply service (FFSS) resource or an alternate.

The Technical Advisory Committee approved NPRR1169 in May but took it up again during a special June 6 call after the PUC called for additional discussion. (See ERCOT TAC Endorses Agreement on ‘Exceptional’ Fuel Costs.)

The R&M approved the measure after adding ERCOT comments that define an FFSS qualifying pipeline as one excluding intrastate gas utility pipelines that serve customers with a higher protection under the Texas Railroad Commission’s curtailment rule than electric generation facilities. The rule assigns a higher priority to human needs customers and local distribution systems that serve human needs customers.

The directors approved seven other NPRRs, two revisions to the nodal operating guide (NOGRRs) and single changes to the retail market guide (RMGRR) and the verifiable cost manual:

  • NPRR1143: allows ERCOT to give charging instructions to energy storage resources during a Level 3 energy emergency alert.
  • NPRR1161, NOGRR246: clarifies that intermittent renewable resources that remain synchronized to ERCOT, but are unable to provide reactive power when not providing real power, do not have to notify ERCOT other than their real-time telemetered status.
  • NPRR1166: changes the expiration date for DC ties’ schedule information protected status from 60 days after the applicable operating day to the date on which ERCOT files the report with the PUC, as required by transmission export rates’ rules related to energy imports and exports over the ties.
  • NPRR1167: improves the new FFSS product by removing language disqualifying or decertifying resources from the firm-fuel program.
  • NPRR1168: changes the Texas standard electronic transaction (Texas SET) to “Establish/Change/Delete CSA Request” and adds new sections to the protocols related to administering requests to change end dates for active continuous service agreements (CSAs).
  • NPRR1177: requires resources to file exceptional fuel costs that include contractual and pipeline-mandated costs, following negotiations between consumer representatives and a generator.
  • NPRR1178: clarifies and updates expectations for resources providing ECRS.
  • NOGRR253: aligns the guide’s language regarding ECRS and nonspin with NPRR1178’s proposed revisions and NPRR1096’s proposed protocol language. The NOGRR would also clarify that ERCOT may manually deploy load resources, other than controllable load resources that are providing ECRS or responsive reserve, to maintain a minimum 500 MW of physical responsive capability reserves on dispatchable resources to balance demand with supply while maintaining stable grid frequency for smaller disturbances.
  • RMGRR172: updates the Texas SET transaction’s name to “Establish/Change/Delete CSA Request” and adds new sections to the guide that describe how to cancel a pending CSA through MarkeTrak.
  • VCMRR031: defines variable costs and clarifies that all cost components used to calculate a filing entity’s fuel adder should also be based on variable costs; removes the minimum requirements fee cost category from being included in the fuel adder; and changes the review timeline to give ERCOT the ability to follow up on more complex cost submissions.

— Tom Kleckner

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Electric Reliability and Safety Continue to Improve in NY

New York’s electric utilities in 2022 showed improved service reliability over 2021 and over the average in the preceding five years. (Case 23-E-0119)

But in other areas, the New York State Public Service Commission found performance by electric and other utilities lacking in 2022. It is assessing a record $22.6 million in penalties against six utilities for failing to meet customer service metrics.

The penalties are one of the sticks in the carrot-and-stick assortment of utility performance incentives contained within the commission’s rate design, and it was a particularly big stick this time: The PSC said the penalties assessed Thursday were 10 times higher than those imposed for 2021 failures.

PSC Chair Rory Christian in a prepared statement said: “In 2022, almost a quarter of those utilities fell short of their legal requirements in certain areas. The Commission will aggressively work to ensure lagging utilities improve performance. Maintaining reliability and ensuring good customer service is required for utilities, and the Commission holds them accountable when they fail to meet our standards.”

Aside from New York State Electric & Gas — which garnered a $7 million revenue reduction for outage frequency — reliability was a bright spot for New York electric utilities in 2022.

Department of Public Service staff said the reliability of the state’s electric utilities is measured by two primary metrics: frequency and duration.

Excluding major storms, frequency was less in 2022 than in 2021 and less than the statewide five-year average. Duration, again excluding major storms, averaged 1.9 hours, 5.4 minutes shorter than 2021 and 4.8 minutes less than the five-year average.

There were 34 major storms in 2022, four fewer than the year before. But the impact of the 2022 storms was much greater than 2021’s storms, with 31% more customers affected and a 100% increase in duration of outage.

The majority of the 2022 increases can be attributed to just three winter storms.

During Thursday’s meeting, Christian called this a worrisome development, illustrating how impactful a single storm can be in an era where severe weather events are becoming more frequent.

Central Hudson, Con Edison, National Grid, Orange & Rockland and RG&E met all reliability targets in 2022. But NYSEG missed its frequency target for the fourth consecutive year.

DPS staff said tree contact continues to be the largest contributing factor in NYSEG’s outages, accounting for 42.1% in 2022, more than any other utility in the report.

The PSC expanded NYSEG’s vegetation management budget in the 2020 rate order; the utility has seen a decrease in outages due to trees within its rights of way since then but an increase in outages caused by trees outside the ROWs.

These “danger trees” outside the ROWs were specifically targeted in one of the programs funded in 2020.

Overall, 82,288 service interruptions affected 5,298,241 customers statewide for a combined total of 10,075,244 hours in 2022. The dataset covers the six regulated electric utilities and PSEG-LI.

On safety measures — stray voltage, gas leaks and other potential hazards — the DPS review found electric and gas utilities in full compliance and continuing a trend of improvement in most respects.

DPS staff in their review said most of the state’s utilities met or exceeded the customer service standards established in their rate case proceedings for metrics such as call answer rate, customer satisfaction survey and PSC complaint rate. The 2022 laggards, and their revenue penalties, are:

Central Hudson, $2.9 million; NYSEG, $8.72 million; RG&E, $5.9 million; Con Edison, $4 million; St. Lawrence Gas, $36,000; National Grid, $1.05 million.

The customer service reports issued Thursday are separate from ongoing DPS investigations into current and past billing problems at Central Hudson, NYSEG and RG&E. But the PSC said the reports could inform the billing investigations.

Also on the consumer protection front, the PSC on Thursday set rules and regulations governing energy brokers and consultants. (Case 23-M-106)

Christian said the move is designed to increase transparency in and oversight of a previously unregulated but rapidly growing area of the clean-energy economy in New York.

The new rules require persons, firms and associations acting as an energy broker or consultant to register annually with the PSC, pay a $500 registration fee, and demonstrate financial accountability. The deadline is Aug. 31, 2023.

The new rules also require disclosure of compensation paid to brokers and establish enforcement procedures.

Rebates from the broker/consultant to the ratepayer are banned, as they could obscure actual costs, and the PSC can order customer rebates to be drawn from a letter of credit that brokers/consultants will have to provide.

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ERCOT Sovereign Immunity Affirmed by Texas Supreme Court

The Texas Supreme Court on Friday narrowly affirmed ERCOT’s sovereign immunity, granting it protection against fraud claims and allegations of overpricing during the 2021 winter storm, and asserted the Public Utility Commission’s jurisdiction over the grid operator in a pair of rulings.

In a 5-4 decision, the state’s high court found that ERCOT is a governmental entity and immune to lawsuits because “it prevents the disruption of key governmental services, protects public funds and respects separation of powers principles.”

The majority held that the ISO is entitled to sovereign immunity because the state’s Public Utility Regulatory Act “‘evinces clear legislative intent’ to vest it with the “‘nature, purposes and powers’ of an ‘arm of the [s]tate government’” and because doing so satisfies the ‘political, pecuniary and pragmatic policies underlying our immunity doctrines’” (22-0056, 22-0196).

Writing for the majority, Chief Justice Nathan Hecht said ERCOT is a “unique entity” and provides an “essential governmental service.” He said ERCOT operates under the PUC’s direct control and oversight, it performs the “governmental function of utilities regulation, and it possesses the power to adopt and enforce rules pursuant to that role.”

“ERCOT’s governmental nature is demonstrated most prominently by the level of control and authority the state exercises over it and its accountability to the state,” Hecht wrote. “In this regard, it is much like a state agency … the state has complete authority over everything ERCOT does to perform its statutory functions.”

In a 53-page dissent that outnumbered the 40-page decision, justices Jeffrey Boyd and John Devine wrote that “the public’s trust is undermined when the judiciary extends sovereign immunity, contrary to history and tradition, to what is undeniably not sovereign: purely private entities.” They called on Texas lawmakers to correct the court’s “mistake” and waive the grid operator’s “newfound immunity” so injured parties have the right “to claim the protection of the laws.”

Thousands of wrongful death and property damage lawsuits stemming from Winter Storm Uri have been combined in pending multidistrict litigation in a district court, where ERCOT is a defendant in most of the cases.

“The root justification for possibly protecting private entities with the [s]overeign’s immunity is that, by statute or contract, they act as arms of the state: the government acted through the entity and the actions are effectively attributed to the government as ‘action taken by the government,’” Boyd and Devine wrote. “Unlike any other entity previously granted immunity by this [c]ourt, no statute designates ERCOT as a part of the government.”

ERCOT said in an emailed statement that it was pleased with the decision.

“The [c]ourt’s careful consideration of these significant legal issues allows us to continue to focus on our core [s]tate responsibilities on ensuring a reliable grid for Texans,” the grid operator said.

The PUC responded that it would “let the ruling speak for itself.”

The decision resolves two separate proceedings the Supreme Court heard in January. (See ERCOT Claims Immunity Before Texas Supreme Court.)

The high court affirmed a 2021 appeals court ruling that ERCOT is a “governmental unit” in a lawsuit brought by San Antonio municipality CPS Energy. The utility alleged that it was short-changed $18 million during the winter storm by ERCOT’s mishandling of power pricing.

It also reversed an appeals court’s judgment that the ISO is a private, membership-based nonprofit, not created or chartered by the state, in a case involving Panda Power that dates to last decade. The developer said ERCOT knowingly produced false market data in 2011 and 2012 reports that led Panda to build three power plants, a $2.2 billion investment that failed to meet its expectations.

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Loan Programs Office Announces $9.2B for Ford Battery Plants in Tenn., Ky.

The Department of Energy’s Loan Program Office (LPO) on Thursday announced a conditional commitment for a loan of up to $9.2 billion to help BlueOval SK, a joint venture between Ford and Korean battery manufacturer SK On, to produce electric vehicle batteries at sprawling plants in Kentucky and Tennessee.

The three plants, one in Tennessee and two in Kentucky, will together be able to produce 120 GWh of batteries per year, to be used in Ford and Lincoln EVs, the LPO announced. Already under construction, the Kentucky plants cover an estimated 2.3 square miles, with battery production to begin in 2025, according to the BlueOval website.

With a 6-square-mile “megacampus,” the Tennessee plant will be the largest in Ford’s portfolio and include both battery manufacturing and a factory for Ford EVs, according to BlueOval. As described on the company website, the plant will “be carbon neutral, use 100% renewable energy, send zero waste to landfill and use fresh water only for human consumption ― as [Ford] moves towards a closed-loop manufacturing process.”

Production in Tennessee also is scheduled to begin in 2025, the company said.

Job creation across all three plants will be about 5,000 during construction, with 7,500 permanent positions. BlueOval is working with community colleges in Kentucky and Tennessee to develop training programs “where thousands of employees will gain the skills required to work at the battery plants,” according to the company announcement.

BlueOval will be building a training facility next to the Tennessee plant to “really [focus] on the curriculum for training, deep learning, and getting people through that part of the training before they come out on the shop floor to be a part of the launch,” said Kel Kearns, the plant manager, as reported by WBBJ in Jackson, Tenn.

The LPO noted that the Kentucky and Tennessee projects are also located near or in disadvantaged communities, reflecting President Joe Biden’s “Justice 40” commitment to ensuring 40% of all federally funded projects benefit low-income and disadvantaged communities.

“The DOE’s commitment to this project will strengthen battery manufacturing in the U.S. while reducing carbon emissions, providing customers with high-performance vehicles, and creating good jobs for future generations,” said BlueOval CEO Robert Rhee.  The company must meet additional LPO requirements before the conditional loan can be finalized.

A Domestic Supply Chain

Building out a domestic supply chain for EV and stationary batteries is a key priority for the LPO, as domestic content in EVs and batteries has become a political flashpoint for Biden’s push to make electric vehicles 50% of all new car sales by 2030.

The industry is highly dependent on China for batteries and the processing of critical minerals in them, including lithium, cobalt and nickel. Sen. Joe Manchin (D-W.Va.) made a U.S. supply chain buildout a key part of the Inflation Reduction Act.

To be eligible for the full $7,500 EV tax credit in the IRA, a vehicle must meet domestic content and assembly requirements.

According to Internal Revenue Service guidelines, to receive the full credit, the final assembly of an EV must occur in North America. In addition, 40% of the critical minerals in the battery and 50% of other battery components must be sourced, processed or manufactured in the U.S. or in a country with which the U.S. has a free trade agreement.

The domestic content percentages go up each year, with critical minerals increasing 10% per year, up to 80% in 2027, while the battery component also will increase 10% per year, rising to 100% in 2029.

Some, but not all, models of Ford’s top EVs — the Mustang Mach-e SUV and F-150 Lightning pickup truck — qualify for the full credit, according to the company website.

The LPO received $3 billion from the IRA specifically for its Advanced Technology Vehicles Manufacturing (ATVM) program, an amount that can be used to provide up to $40 billion in loan authority, according to an online fact sheet.

The BlueOval announcement is the latest conditional loan from the ATVM program. This month, the LPO made a conditional commitment for an $850 million loan to KORE Power for an Arizona plant that will produce battery cells to be used in both EVs and grid-scale stationary storage. (See LPO Announces $850M Conditional Loan for Ariz. Battery Cell Plant.)

In March, the office also announced a $375 million conditional loan to Li-Cycle Holdings to develop North America’s first recycling facility for battery-grade lithium, to be located in New York. (See DOE OKs $375 Loan for NY Battery Recovery Plant.)

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FERC Rejects PG&E Standard Interconnection Agreement

FERC rejected a controversial pro forma transmission-to-transmission interconnection agreement filed by Pacific Gas and Electric that the utility said was modeled on CAISO’s large generator interconnection agreement as a means to streamline its interconnection process.

“PG&E states that the pro forma IA [interconnection agreement] will standardize and simplify new agreements and provide transparency and predictability for interconnection customers that are interconnecting their transmission system or transmission facility to PG&E’s transmission system,” FERC said (ER23-1661).

The utility argued that the new IA would “create efficiency since it anticipates 15 new or replacement interconnection agreements through 2025,” the commission said.

CAISO plans and operates PG&E’s transmission system, and its pro forma large generator interconnection agreement (LGIA), with revisions for transmission interconnections, contains “many terms and definitions … consistent with CAISO’s tariff, PG&E said as part of its explanation of why it had used it as a model.

The proposal elicited a slew of protests from utilities, state and federal agencies and balancing authorities that offered 18 categories of reasons why the standardized agreement would be unreasonable and discriminatory to those seeking to connect to PG&E’s sprawling transmission grid.

“Protestors request that the commission reject the pro forma IA or, in the alternative, that the commission establish hearing and settlement judge procedures,” FERC said. “Several protestors … note that the commission has never approved a pro forma ‘load’ interconnection agreement, and instead reviews interconnection agreements on a case-by-case basis.”

One group of protesters called the “Indicated Public Entities” included the city and county of San Francisco, the Northern California Power Agency, the Transmission Agency of Northern California, the Sacramento Municipal Utility District, the Port of Oakland and three irrigation districts that generate electricity.

“Indicated Public Entities argue that PG&E’s desire to ease negotiation of new interconnection agreements is no justification for limiting interconnecting entities’ ability to negotiate terms based on their own circumstances,” FERC said.

The U.S. Department of Energy, the Western Area Power Administration, and the California Department of Water Resources filed motions to intervene and protests.

“DOE asserts that providing uniformity is an insufficient justification for terms of the pro forma IA that conflict with legal rights and obligations of the United States,” FERC said.

DOE also emphasized that PG&E had not adequately explained why it had chosen CAISO’s pro forma LGIA as a “useful or appropriate template for transmission-to-transmission system interconnections,” the commission said.

FERC agreed with the arguments made by DOE and others.

“Rather than explaining why the specific provisions of its proposed pro forma IA are just and reasonable and not unduly discriminatory or preferential in their own right, PG&E places significant emphasis on the fact that it used the CAISO pro forma LGIA as a template for its proposed pro forma IA, and that the Commission previously accepted similar interconnection agreements,” FERC said.

But “CAISO’s pro forma LGIA is designed to address the specific issues associated with the interconnection of a generator to CAISO’s transmission system,” it said. “System-to-system interconnections raise different issues and require different considerations than those addressed in an LGIA.”

In addition, PG&E’s proposal included “significant deviations from CAISO’s LGIA without sufficient explanation, FERC found.

Another main reason FERC said it rejected PG&E’s proposal was because it “contemplates a pro forma IA that includes individually tailored and negotiated appendices that will replace existing IAs when they terminate.”

“We find that PG&E has not adequately explained how the individually tailored and negotiated appendices will be used to capture the customer-specific requirements of PG&E’s differently situated interconnection customers,” FERC said.