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November 13, 2024

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Participants ‘Unwaveringly Committed’ to WRAP, WPP CEO Says

DENVER — Western Resource Adequacy Program (WRAP) participants still strongly support the program despite recently appealing to delay its “binding” penalty phase by one year based on concerns about capacity shortages, Western Power Pool (WPP) CEO Sarah Edmonds said April 24. 

But Edmonds acknowledged the appeal clearly signals the RA situation in the West is much more critical than previously thought. 

“[Participants] are still unwaveringly committed to WRAP, which is good news for us, because our belief in the urgency and the need for the program has not changed,” Edmonds said during a panel discussion at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in downtown Denver. “If anything, it’s only increased in this era of heightened reliability risks and NERC [and] WECC assessments warning us for quite some time that we have a serious issue that we’re facing,” she said. 

Edmonds’ comments came two days after the WRAP’s Resource Adequacy Participants Committee (RAPC) issued an April 22 letter saying program members would postpone binding operations to summer 2027 because some of them confront “significant new headwinds” in securing sufficient energy resources to meet their capacity obligations and avoid heavy penalties in the WRAP’s FERC-approved tariff. (See WRAP Participants Seek 1-Year Delay to ‘Binding’ Operations.) 

The letter cited problems with new resources’ supply chains, forecasts for faster-than-expected load growth and “extreme weather events” that have challenged assumptions about the volume of resources needed to maintain grid reliability as key reasons the delay is required. 

“The RAPC letter is an illustration of the fact that we are shorter than we thought as a collective, and there is not critical mass. And in terms of WRAP, we are facing more resource inadequacy going forward,” Edmonds said. 

Participants are looking to “revisit” WRAP “transition provisions” providing “discounts” to penalties and offer measures “that make it easier to become binding in this program,” Edmonds noted.    

WRAP entities face a May 31 deadline to commit to the binding phase beginning in summer 2026, but stakeholders determined the program would not obtain a “critical mass” of participation by that time, she said. 

The WRAP’s tariff allows WPP to commence binding operations anytime between 2025 and 2028. Participants will work to position the program for participants to commit in May 2025 for the summer 2027 binding phase, a change requiring stakeholder approval. 

“I hope that’s the last marker,” Edmonds said.  “Summer of 2028 is the very last moment — that’s when everyone in this program who’s still there needs to be fully binding.” 

Edmonds said the nonbinding phase of the program still offers “a lot of value.” 

“We’re essentially in an informational stance where we’re going through a lot of the processes — the forward-showing, planning process — and then essentially setting up an operational program that can track how it would really look in real life if we were in this program,” she said.  

“We could do better on all those pieces in terms of the quality of the data that we’re receiving from participants, the amount of data the Western Power Pool is permitted to see in the tariff, and how we can then explain that data and turn that data into information that’s useful for the region,” she added. 

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FERC Sticks with MISO on Queue Penalties over Clean Energy Groups’ Rehearing Attempt

Clean energy groups were unsuccessful with FERC in their challenge of automatic withdrawal penalties in MISO’s interconnection queue.  

The commission decided April 25 that MISO is clear to continue use of an automatic and escalating penalty structure despite a joint rehearing request from the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance (ER24-340).  

“Commission precedent and the record in this proceeding demonstrate that interconnection withdrawals create a generalized harm in MISO that more than inconveniences remaining interconnection customers in MISO’s interconnection queue,” FERC wrote to justify MISO’s penalty setup.  

Under the penalty schedule, MISO can keep 10% of a developer’s per-megawatt milestone fees at the queue’s first decision point, 35% by the second decision point, 75% by the time their project reaches the third and final phase of the queue and, finally, 100% if they drop out during the negotiation stage of the generator interconnection agreement. 

The penalty fees were imposed early this year as part of a package of rules meant to downsize MISO’s interconnection queue and discourage speculative projects. This week, MISO announced it received 123 GW of project proposals under its 2023 queue cycle, less than the 171 GW it fielded in 2022. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.)  

The clean energy groups had argued the penalties would have a chilling effect on generation entering the MISO queue because the fees would rack up before developers receive meaningful study results from the RTO on the feasibility of their projects. They argued FERC treaded on its own philosophy that penalties shouldn’t discourage interconnection customers from lining up projects or withdrawing them in an orderly fashion. (See Clean Energy Groups Seek FERC Re-evaluation of Automatic Penalties in MISO Queue.)  

However, FERC said the penalties will persuade developers to withdraw nonviable projects “before MISO has expended significant resources studying such requests.” It also said its precedent doesn’t necessarily prohibit automatic fines.  

“We find that neither the establishment of an automatic withdrawal penalty nor the amount of the penalty creates a barrier to enter MISO’s interconnection queue; rather, such a penalty reinforces an existing consequence of withdrawing an interconnection request,” FERC said. “While it is true that [penalties] may discourage the submission of speculative interconnection requests or encourage earlier withdrawals to avoid higher penalties, those outcomes are not unreasonable barriers to entering the interconnection queue.” 

FERC also agreed with MISO that automatic forfeitures will serve as an “appropriate mechanism to disincentivize speculative interconnection requests from entering the queue.” 

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Texas RE Auditors Push Preparedness for Security Walkthroughs

Compliance auditors at the Texas Reliability Entity urged utilities April 24 to think of them not as antagonists looking to get them in trouble, but as allies in the mission of maintaining grid reliability. 

“We’re not looking for more work,” Paul Hopson, compliance team lead at Texas RE, said at the regional entity’s Spring Standards, Security and Reliability Workshop in Austin. “We’re looking for compliance, of course. We want to help you get there. Believe me, we will. We’ll stay there all week … and even more time if we need to, to help you show compliance. If you need more time, we’ll be happy to review whatever you want to give us to look at. But our job is to ensure the reliability and stability of the grid.” 

Hopson’s presentation focused on how responsible entities should prepare for walkthroughs performed during audits related to NERC’s Critical Infrastructure Protection (CIP) standards, which govern both physical and digital security. He said walkthroughs can help identify issues in both areas. 

Entities often think of physical security as limited to installations, like fences, gates and barriers to deter unauthorized access, cameras to monitor activity around the site, and access-control measures such as keycard readers and alarms, Hopson said, with cybersecurity seen as a separate specialty. 

However, he noted there is actually considerable crossover between these areas. For example, CIP-006-6 (Cybersecurity — Physical security of BES cyber systems) requires entities to secure the physical points of access to certain grid cybersystems. As a result, utilities should be aware that cybersecurity audits may involve site visits in addition to software inspections. 

“When we go on-site, and we’re doing these reviews … we’re going to look through these things,” Hopson said. “We may not check every door lock; we may not look for every cyber asset that … wasn’t in scope. But since we’re there … we’re going to try to point out any vulnerabilities.” 

Hopson was asked what auditors would do if they noticed a deficiency with a CIP standard that was outside the scope of their audit. He acknowledged that while the team would not expand the scope on the spot, “if there’s something that … leads to a noncompliance, yeah, we are going to have to have that discussion” with the utility’s staff. 

He emphasized that this is not just a hypothetical situation, but something his team has encountered numerous times. When he joined the compliance team in 2016, Texas RE auditors performing compliance checks for CIP-012-1 (Communications between control centers) also frequently would find issues with the CIP-006 standards. 

Although they did not specifically check for such problems, they were easy to spot for auditors familiar with both standards because the CIP-012-1 audit required they be in control centers where the access hardware for cybersystems was visible. 

Hopson said that entities have been “doing a much better job” with CIP-006 compliance in recent years, but auditors still keep their eyes open when performing a CIP-012 audit because “that’s just part of our risk-based approach.” When asked what long-term effects such a finding would have besides a recommendation to the registered entity involved, Hopson acknowledged auditors would notify the RE’s Risk Department, and the CIP-006 deficiency “may end up on an audit in the future.” 

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EPA Antes up Nearly $1B to Replace Diesel Heavy-duty Vehicles

EPA on April 24 announced nearly $1 billion in grants from the Inflation Reduction Act to help cities, states, territories and school districts trade in their older, diesel-burning heavy-duty trucks and buses for new zero-emission vehicles.  

The $932 million competitive funding opportunity for the 2024 Clean Heavy-Duty Vehicles Grants Program is aimed at covering part of the cost of a range of Class 6 and 7 HDVs, as well as charging equipment and workforce training programs. 

Class 6 vehicles (19,501 to 26,000 pounds) include school buses; bucket trucks, such as cherry pickers; and different kinds of delivery vehicles, referred to as step vans and box trucks. Class 7 vehicles (26,001 to 33,000 pounds) include transit buses, garbage trucks and street sweepers. 

According to EPA, more than 3 million Class 6 and 7 HDVs are on the roads in the U.S. Transportation accounts for 29% of U.S. greenhouse gas emissions, and medium- and heavy-duty trucks make up 23% of that total, according to the agency. 

The “historic” funding will help “ensure every community can breathe clean air,” EPA Administrator Michael Regan said in a statement. The IRA dollars also could advance U.S. competitiveness in international markets, Regan said, securing “our nation’s position as a global leader in clean technologies that address the impacts of climate change.” 

Sue Gander, director of the World Resources Institute’s Electric School Bus Program, hailed the new funding as “a game changer for communities across the country that want to transition to clean buses and trucks — and breathe cleaner air — but don’t have the means to do so. … 

“Heavy-duty vehicles emit huge amounts of air pollution that harm the health and wellbeing of our children and communities. Historically underserved communities living near depots, ports and highways are often more exposed to pollution from these vehicles, underscoring the equity benefits of this program,” Gander said in a statement on the WRI website. 

According to the funding announcement, EPA expects to award approximately 40 to 160 grants, ranging from $500,000 to $60 million per award. The deadline for applications is July 25, with awards announced and finalized by the end of the year. 

The awards will be split between two subprograms, with 70% of total funds going to school buses and 30% for “vocational vehicles,” which include other types of Class 6 and 7 HDVs. 

Other carveouts require that $400,000 of the grants be awarded in “nonattainment” regions that do not meet national air quality standards, and at least 15 grants go to tribal groups and territories. 

States, territories, cities, public school districts, tribal governments and nonprofit school transportation associations are eligible for the funds. 

Cost shares for the grants will depend on the type of HDV and whether it is a battery-electric or hydrogen fuel cell vehicle. The lowest cost share is 33% for an electric transit bus, and the highest is 80% for a range of hydrogen fuel cell Class 6 vehicles. 

EPA’s top priority for replacements are diesel-powered HDVs from model year 2010 or earlier, but other HDVs with internal combustion engines and from model years 2011 and after also may be eligible. The new electric or fuel cell HDVs should be from model year 2023 or later. 

Awards can also be used to cover behind-the-meter charging infrastructure — from Level 2 chargers and battery storage units to new electric panels and meters — but not transformers. 

Clean Freight Strategy

The HDV grant program was one of a series of April 24 funding announcements from the Biden administration to promote a new initiative aimed at setting a national goal for the U.S. to develop a zero-emissions freight strategy, covering trucks, rail, aviation and marine vehicles. 

The administration has committed to working with other countries to build clean HDV markets in which 30% of new medium- and heavy-duty vehicle sales will be zero-emission by 2030 and 100% by 2040, according to a White House fact sheet. 

The Department of Transportation announced $148 million for 16 grants to 11 states and Puerto Rico “to improve air quality and reduce pollution for truck drivers, port workers and families that live in communities surrounding ports.” 

The grants are the first round of the department’s $400 million Reduction of Truck Emissions at Port Facilities Grant Program, created by the Infrastructure Investment and Jobs Act. 

For example, Georgia is receiving $15.3 million to build a large-scale charging project near the Port of Savannah, which will allow the replacement of diesel-powered trucks and expand the use of other low- and zero-emission equipment at the port. 

“When truckers spend hours idling at ports, it’s bad for drivers, bad for supply chains and bad for nearby communities that feel the brunt of more polluted air,” Transportation Secretary Pete Buttigieg said in a statement. “The investments we are announcing … will save truck drivers time and money and help ports reduce congestion and emissions, while making the air more breathable for workers and communities.” 

According to the White House, the Department of Energy is also putting up $72 million for a “SuperTruck: Charged” program to demonstrate how vehicle-to-grid integration at depots and truck stops will “provide affordable, reliable charging while increasing grid resiliency.” 

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Policymakers Chart FERC’s History of Opening the Grid for Competition

FERC has worked to restructure the power industry for nearly three decades, and now it is poised to take another major step forward on that front with the transmission rule next month, panelists said on a webinar April 24 hosted by Americans for a Clean Energy Grid. (See FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming.) 

Congress first started opening up the grid with the Public Utility Regulatory Policies Act in 1978, said Sen. Ed Markey (D-Mass.), noting that he supported the law just after being elected to the House of Representatives. 

“For the first time, utilities had to buy power from qualifying small generators that were not utilities, but utilities didn’t want to give up ownership of the transmission system,” Markey said. “They didn’t want anyone else to have real access. And we had won a battle on interconnection, but we had not won the war.” 

ferc grid

Sen. Ed Markey (D-Mass.) addresses ACEG’s webinar on April 24. | ACEG

It took more than a decade for Congress to take up the Energy Policy Act of 1992, which included language requiring open access to utilities’ transmission lines that Markey had worked to introduce from his seat on the Energy and Commerce Committee. 

“I had to negotiate with the Senate Energy [and Natural Resources Committee] chairman, Sen. Bennett Johnston [D] of Louisiana, who had a utility that was … I’ll put it like this: hesitant to adopt it,” Markey said. “That’s not their natural attitude down there in Louisiana and Arkansas to welcome competition, but it got included. But still, the utilities did successfully limit the scope of open access. So, if a small generator wanted transmission access, they had to file for it.” 

At that point, FERC stepped in and issued Order 888 in 1996 that required all utilities under its jurisdiction to have full open access of their transmission systems and led to the restructuring of the wholesale side of the power industry, he added. 

“Look, 888 was a huge, great beginning,” said former Commissioner Nora Mead Brownell. “But let’s face it: Monopolies do not go well quietly into the night. So, when we got to FERC, there was the California energy crisis, which we had to solve.” 

The 2000-2001 energy crisis involved a lot of litigation and FERC creating the Office of Energy Infrastructure Security, the focus of which was underinvested in by California — making the crisis possible, Brownell said. 

FERC always has commissioners appointed by both political parties, and while the commission in the early aughts had plenty of behind-the-scenes debates on specific policies, they were all moving in the same direction to open up the markets, she said. That commission, led by Chair Pat Wood III, approved new RTOs and helped to lay some of the basic rules for their markets out. 

Prior to his election to Congress in 2018, Rep. Sean Casten (D-Ill.) worked in the industry developing power plants. He recalled Congress’ and FERC’s work to raise nuclear plant capacity factors and roll out combined cycle plants around the country. 

“Why did markets do that?” Casten said. “Well, they did that because regulated utilities are really good at reliability; they are really good at keeping the lights on. They are really bad at innovation and really bad [at] cost planning. That’s not a criticism; the market needs both things.” 

Order 888 gave industry participants the ability to make money by deploying cheaper assets for the first time in the power industry’s centurylong history, he added. It also proved to be a win for the environment, as it ensured coal plants would face competition, to which they lost, Casten said. 

FERC has been tweaking the rules of markets ever since, but Casten said that so far, it has fallen short of major reforms to curtail market power and get beyond the still-often-fragmented nature of the grid. 

“They’ve been really too slow in addressing interregional issues, cost issues [and] the growing interconnect delay on the system,” Casten said. “Those are problems they have the jurisdiction to fix. And we’re out of time for talk; we got to start moving forward.” 

Markey also called for further reforms, noting the country needs to double the pace of transmission expansion to fully use the incentives from the Inflation Reduction Act and build even more lines to hit net-zero targets. 

Brownell wants to see FERC step up its monitoring abilities so it can get a better handle on market power issues but also be informed about the planning issues, on which it tends to default to the information provided it by the ISO/RTOs. 

“I think we could use [the Department of Energy] as a backstop to validate some of the planning assumptions and plans that come out of the RTOs,” Brownell said. “I think the RTOs are doing the best they can under the circumstances. I don’t think we’re rewarding them for the right things, and I don’t think we’re rewarding them for making progress.” 

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Congestion Revenue Rents Still Underfunded, CAISO DMM Says

Congestion revenue rights (CRRs) auctions averaged $62 million in losses between 2019 and 2023, down nearly $50 million since changes were implemented in 2019 but “still very high,” said CAISO’s Department of Market Monitoring (DMM) during the ISO’s Annual Policy Initiatives Roadmap Process meeting April 22. 

CAISO staff and stakeholders questioned if the consistent underfunding of CRRs should be taken up as an official initiative. 

CRR auctions have been losing money for more than a decade, and CAISO has taken multiple steps to address the revenue inadequacy. In 2019, the ISO instituted rule changes meant to decrease the amount of money flowing from ratepayers to commodities traders, which reduced losses significantly, the DMM said. (See CAISO CRRs Still Losing Money, but Less.) Auction revenues for transmission ratepayers averaged 67 cents per dollar paid to CRRs since 2019, compared to about 48 cents before the changes. Almost all losses stem from rights bought by financial traders, according to the DMM. 

In May 2020, CAISO released a report evaluating the rule changes and identified that an issue with the shift factor threshold — which is used to evaluate the effectiveness of energy bids to manage congestion in the clearing of the day-ahead market — was causing additional underfunding. 

“Even though the CAISO did address that issue, we are still seeing quite a bit of revenue inadequacy and underfunding,” Kallie Wells, senior consultant at Gridwell Consulting, said in her presentation on the issue. 

The changes implemented to address the shift factor threshold primarily impacted low-voltage lines, Wells said, with recent CRR revenue inadequacy affecting higher voltages. However, 25% of low-voltage constraints still saw recent funding levels of just 20%. Underfunding appears to be related to more than just transmission derates, Wells added, questioning the root causes of the continued revenue inadequacy. 

“The ask that we have of … CAISO to include in terms of potential scope on a CRR enhancements policy is really getting at what are the root causes or drivers of the current revenue inadequacy,” Wells said. “It’s really unclear to us what those underlying factors are and whether or not they continue to align with cost causation principles.” 

Because of how CRRs are allocated, rights are becoming a liability rather than a reliable source of revenue, Wells said. And congestion is increasing; she pointed out that the first quarter saw the most congestion in five years, further emphasizing the importance of CRRs in CAISO’s market. 

“The role that CRRs play is extremely important in an organized energy market, and if we’re having this issue with how the shortfall is being allocated to the CRRs and causing the CRRs to be a risk or a liability for entities to hold and not functioning properly as a hedging tool, that’s extremely concerning,” she said. 

Wells provided policy suggestions for addressing the problem, including capping underfunding and using more overfunding to offset deficits. 

DMM Again Recommends Replacing CRR Auctions

The DMM continues to suggest that forgoing the CRR auction in place of a financial market based on offers from willing sellers could solve the underfunding problem. 

“Ever since CRRs were implemented over 10 years ago, the auction revenues that are brought in in the auction fall way short of the congestion revenues that get paid out,” said Eric Hildebrandt, the department’s executive director. “So, from that perspective, there is a net loss to transmission ratepayers as a result of the CRR auction. 

“The difference in the DMM proposal from the market that exists today is, rather than the ISO auctioning rights … there would be a financial auction in which those entities that held rights could offer them for sale to other entities.” 

Under the proposal, CRR allocations could remain unchanged, or alternatively, congestion revenues could be refunded to load-serving entities instead of being allocated. A purely financial CRR market would be run with other voluntary bids to buy and sell CRRs and “would be easier and less subject to errors than [the] current CRR model based on a physical network,” Hildebrandt said. 

But some stakeholders raised concern that replacing the auction with a financial market could stifle competition and liquidity. 

“With auctions, the reason we have more than just load-serving entities participating in them is to inject competition into the market,” said Noha Sidhom, an Energy Trading Institute board member. “And so, my concern when I hear some of this is I just worry about lack of competition and lack of liquidity.” 

Seth Cochran, head of strategic market policy at Vitol, echoed Sidhom’s concerns. 

“There’s a strong assumption embedded in here that you can create a replacement market and everything will be fine,” he said. “I know you’re trying to put together a substitute here, but I can tell you from decades of experience in the market that you’re just not going to be able to foster liquidity, and it’s really going to leave the [independent power producers] out to dry. I know it might sound good on paper, but this is totally untested and unproven.” 

Because of prior commitments from the ISO and the Market Surveillance Committee to address the issue, the DMM recommended the topic not be taken up as a discretionary initiative and received stakeholder support. Hildebrandt did note, however, that while CAISO and the committee began discussion of CRR losses in 2023, they’ve “been silent since.” 

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Interior Announces Updated OSW Regs, Auction Schedule at IPF24

NEW ORLEANS — The U.S. Department of the Interior has set a new five-year schedule for as many as a dozen new offshore wind energy lease auctions and finalized an update of its regulations for renewable energy development in U.S. waters. 

Secretary of the Interior Deb Haaland announced the news April 24 at the 2024 International Partnering Forum, where more than 3,000 stakeholders and prospective stakeholders gathered for an update on the offshore wind industry. 

“The updated rule modernizes existing regulations and streamlines and eliminates those that are overly complex or unnecessary,” she said, building on lessons learned in the nearly 15 years since the original rule’s issuance. 

Haaland added that it “will ensure that we build out the offshore wind industry effectively and efficiently at the pace that our future demands, [with] safety and environmental protections at top of mind.” 

Also April 24, the Department of Energy issued its “Pathways to Commercial Liftoff: Offshore Wind” report and announced $48 million in funding for R&D projects for the sector.  

The Biden administration has set a goal of 30 GW of offshore wind installed by 2030 and 15 GW of floating wind installed by 2035. DOI and its Bureau of Ocean Energy Management have pursued this vigorously, and the department’s announcements took an enthusiastic tone. 

“There will be bumps in the road but together I know we can achieve great things,” Haaland said. “The offshore wind industry is here. And it’s here to stay.” 

Regulatory Update

The updated framework for renewable energy development on the U.S. Outer Continental Shelf was issued April 24 as the “Renewable Energy Modernization Rule.” 

In its announcement, Interior said the rule “increases certainty and reduces the costs associated with the deployment of offshore wind projects by modernizing regulations, streamlining overly complex processes and removing unnecessary ones, clarifying ambiguous regulatory provisions, and enhancing compliance requirements.” 

Interior estimates the U.S. offshore wind industry will realize $1.9 billion in savings over the next 20 years as a result. 

The final rule will be published in the Federal Register in the coming days. The unofficial text and a fact sheet already are online. 

Its executive summary identifies eight key provisions with the following benefits: 

    • eliminates unnecessary requirements for meteorological buoy deployment; 
    • increases survey flexibility; 
    • improves the facility design, fabrication and installation certification and verification process; 
    • establishes a public renewable energy leasing schedule; 
    • reforms BOEM’s renewable energy auction regulations; 
    • tailors financial assurance requirements and instruments; 
    • clarifies safety management system regulations; and 
    • clarifies and strengthens oversight of critical safety systems and equipment. 

Auction Schedule

The wind lease sale schedule that Interior announced is extensive, stretching from the Atlantic to the Gulf of Mexico to the Pacific and even a U.S. territory. 

In the announcement, Haaland took a poke at President Biden’s predecessor and potential successor, former President Donald Trump, saying the Trump administration stalled the start of offshore wind in U.S. waters and the Biden administration has expedited it. 

“Routinely issuing a leasing schedule demonstrates our commitment to a long-term portfolio of leases and provides advance notice to stakeholders of the areas that are being considered for future lease sales, and facilitates planning by tribes, states, localities, interest groups, academia, nonprofits, fisheries, federal agencies and other stakeholders,” BOEM Director Elizabeth Klein said in the announcement. 

The new schedule lays out a roadmap for 12 lease sales: 

    • 2024: Central Atlantic, Gulf of Maine, Gulf of Mexico, Oregon. 
    • 2025: Gulf of Mexico. 
    • 2026: Central Atlantic. 
    • 2027: Gulf of Mexico, New York Bight. 
    • 2028: California, a U.S. territory, Gulf of Maine and Hawaii. 

An overview posted online indicates the 2024 Central Atlantic auction will be first, followed by the Gulf of Mexico auction in September and the Oregon and Gulf of Maine auctions in October. 

BOEM will continue to work with the Intergovernmental Renewable Energy Task Forces to coordinate potential lease sales. 

Liftoff Report

The Liftoff report acknowledges the well-publicized challenges facing offshore wind, which has suffered contract cancellations, cost increases and project delays. But it paints an optimistic picture: 

“Despite recent macroeconomic challenges, the sector is adapting, and improved risk mitigation is being built into industry planning. U.S. offshore wind is now poised for Liftoff, beginning with the 10–15 GW of projects with a path to final investment decision in the next few years.” 

Deputy Secretary of Energy David Turk, who took the stage before Haaland at IPF24 on April 24, said in the official announcement: “The offshore wind sector is making rapid progress even in the face of macroeconomic challenges, poising the industry to create good jobs and supporting a clean, resilient energy system.” 

The cost increases slamming the offshore wind industry in the past few years have begun to ease and there is a path to cost reductions, the report says. 

Offshore wind presents a compelling value proposition, the report states: It advances decarbonization goals, offers a good capacity factor and can bolster the economy’s maritime and domestic manufacturing sectors. 

The report says the potential exists for a U.S. buildout exceeding 100 GW by 2050.  

Arrayed against that potential are four key challenges: Recent offtake cancellations, risky market structures, difficulty with long-term planning visibility and, of course, transmission constraints. But multiple potential solutions are in play for each, the report indicates. 

The liftoff report and a one-page summary are available online. The Department of Energy has scheduled a webinar on the report for May 10. 

Additional IPF24 Coverage 

Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here: 

Central Atlantic Region Prepares for OSW Development

How Best to Address OSW’s Effects on Fisheries

Louisiana Manufacturers Expand into Offshore Wind

Moving Offshore Wind Beyond Contract Cancellations

New York Starts Another OSW Rebound

Offshore Wind Sector Leaders Emphasize Tailwinds

Voices of the OSW Supply Chain, as Heard at Trade Show

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ERCOT Board of Directors Briefs: April 22-23, 2024

Controversial IBR Rule Change Remanded Back to TAC

More than 12 months of negotiations and meetings between ERCOT staff and stakeholders have failed to resolve their differences on a rule change imposing ride-through requirements on inverter-based resources.

ERCOT’s Board of Directors on April 23 punted the issue back to the Technical Advisory Committee, directing that the Nodal Operating Guide revision request’s (NOGRR245) language be modified to address reliability concerns.

“I don’t think it’s ready for approval in its current state,” Director Bob Flexon, chair of the Reliability & Markets Committee, said April 22 after staff and stakeholders made presentations to the R&M. “I’d like to see kind of less daylight between the two positions that are out there.” 

“I’m agreeing that this is not a finished discussion,” Director Linda Capuano said. 

The board unanimously approved R&M’s recommendation to remand the NOGRR to TAC. The Office of Public Utility Counsel abstained from the vote. 

Eric Goff, who has served as the lead spokesperson and represented the interests of renewable developers during the process, asked for direction from R&M as to whether TAC should bifurcate new versus existing resources within the NOGRR.  

When ERCOT first proposed the guide change in January 2023, it specified ride-through requirements for existing IBRs and required strengthened obligations for future IBRs by requiring compliance with the Institute of Electrical and Electronics Engineers’ standards as soon as reasonable. 

“All our disputes so far have been about existing resources,” he said. “TAC did not bifurcate at ERCOT’s request previously. I think it would be helpful to know if you want us to do that.” 

“TAC needs to work with ERCOT,” Flexon responded. “[We’ll] let you guys work it out, since you’re all the experts.” 

The revision request already has generated nearly 80 filings. It’s meant to align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the IEEE’s standard for IBRs interconnecting with the grid. Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances I and II, have added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.) 

Stakeholders have proposed software changesfixing the issues NERC and ERCOT have identified and have said continued regulatory uncertainty could put a damper on further investment in Texas. Unable to reach a compromise with ISO staff, TAC in March approved amended language that stakeholders pushed through over ERCOT’s objections. (See ERCOT Technical Advisory Committee Briefs: March 27, 2024.) 

“It appeared that we had reached a point where additional progress between ERCOT and joint commenters was unlikely based on the foundational differences in language that came to the March TAC meeting,” Oncor’s Collin Martin, TAC’s vice chair, said. 

ERCOT staff again focused their comments on grid reliability, saying the NOGRR’s latest version does not address the “current, critical” reliability risk they sought to mitigate. Dan Woodfin, vice president of system operations, said stakeholders’ proposed exemption process from the new standard for existing IBRs would leave up to 30 GW of resources that wouldn’t have to comply with the new standard. 

“The whole point of trying to do this going forward is that that standard is better than what our current standards are,” he said. “Under the TAC-approved version, if a unit fails to meet [its] currently applicable requirements, they can request an exemption that sets a new standard going forward. If they fail to meet that, then they can ask for another exemption.  

“And my question is, what is the point of a standard when anytime you fail it you can ask for an exemption to set a lower standard going forward?” 

“At the end of the day, resource owners, operators, manufacturers and investors want the same thing as ERCOT: to rely on and support a reliable grid,” said Sara Parsons, Avangrid’s vice president of development. “To succeed in that, however, we need clear and understandable rules for reliability based on both engineering principles and economic principles that enable plants to keep operating and businesses to keep investing.” 

IMM’s McDonald Meets R&M

Jeff McDonald, director of the ERCOT Independent Market Monitor, made a brief appearance before the Reliability & Markets Committee to brief directors on his first five weeks on the job. 

He said the IMM team’s work has been focused on changes to ERCOT contingency reserve service, an ancillary services study, and preparations for supporting the performance credit mechanism’s development. On May 1, the IMM plans to share its annual report on the state of ERCOT’s market with the PUC for its review. 

“To the extent I’ve been involved in those conversations, I’ve seen fantastic cooperation between PUC staff or ERCOT staff and the IMM staff,” he told the committee. “Those efforts have been fantastic to watch, with everyone coming together and trying to move forward.” 

McDonald was named the IMM’s director in March. He replaced Carrie Bivens, who resigned from the position in November after 3 ½ years following several disagreements with PUC and ERCOT leadership. (See Bivens Resigns as ERCOT’s Market Monitor.) 

McDonald has 22 years of experience monitoring wholesale markets. He has led ISO-NE’s Internal Market Monitoring Unit and was senior manager of CAISO’s Market Monitoring Unit. Previously, he was vice president of Concentric Energy Advisors and principal of Libertas Market Analysis. 

ERCOT Manages Total Eclipse

Woodfin told R&M that ERCOT breezed through the April 8 solar eclipse. Sort of. 

“It wasn’t quite as easy as what I read in the newspaper, but we did make it through,” he said. 

Solar generation dropped from 13.8 GW to about 700 MW at its low point at 1:36 p.m. CDT. Solar production once again hit 13.8 GW by 3:10 p.m. 

Woodfin said ERCOT procured extra ancillary services, committed extra generation and took some manual actions to ensure there was enough headroom as various resources ramped up and down. Cloudy skies in portions of the state also reduced the eclipse’s effect. 

“It was certainly less than a clear-sky-type day,” Woodfin said. 

ERCOT’s solar production during the April 8 total eclipse | ERCOT

Board OKs $435M Project

The board approved several items already endorsed by TAC: 

The board also approved two nodal protocol revision requests (NPRRs) and a change to the Retail Market Guide (RMGRR) that: 

    • NPRR1197: Enables resources to separately meter and settle loads located behind ERCOT-polled settlement meters at their points of interconnection. 
    • NPRR1205: Strengthens ERCOT’s market entry eligibility and continued participation requirements for counterparties by clarifying minimum credit quality qualifications for banksissuing letters of credit and insurance companies issuing surety bonds on behalf of market participants. 
    • RMGRR177: Clarifies a customer’s lease agreement option when a competitive retailer tries to remove a switch hold applied to a premise it is seeking to enroll. 
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New Initiative Focuses on Interregional Tx Coordination in the Northeast

An early-stage collaboration between the Acadia Center and Nergica is intended to bring together communities, tribes, nonprofits, companies, RTOs and government officials from the northeastern U.S. and Canada to increase coordination around interregional transmission. 

Dubbed the Northeast Grid Planning Forum (NGPF), the effort is aimed at changing the conversation around transmission planning throughout the broader region to help unlock infrastructure investments, improved planning processes and market changes to help facilitate the clean energy transition.  

“If you look out at what states and provinces are trying to achieve with meeting climate goals,” Dan Sosland, president of the Acadia Center, told RTO Insider, “there is a tremendous amount of potential complementary benefits that could be obtained if we step back and look at how the grids might coordinate in a more intentional way.” 

The entire region faces the potential for massive load growth over the coming decades, coupled with significant changes in how and where electricity is generated. Hydro-Québec anticipates its demand will double by 2050, while ISO-NE forecasts its peak load to reach up to 57 GW, compared to the 24-GW peak experienced in 2023. 

The transmission investments needed to meet this load growth will be pricey: Hydro-Québec has proposed to invest $45 billion to $50 billion by 2035 to expand its transmission capacity, while ISO-NE has estimated that transmission upgrades needed by 2050 could cost up to $26 billion. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.) 

“We need to think about the grid in a different way,” Sosland said, adding that transmission infrastructure throughout the Northeast has been developed largely project by project, leading to projects scattered across the map like “a game of pick-up sticks.” 

Meanwhile, several studies have found that increased interregional transmission capacity throughout the Northeast could bring cost, reliability and decarbonization benefits to ratepayers.  

The U.S. Department of Energy specifically highlighted congestion issues between New York and New England in its 2023 National Transmission Needs Study, which found the need for an additional 3.4 to 6.3 GW of transfer capacity between the regions in scenarios with moderate load growth and high renewable energy penetration.   

Along with resource adequacy benefits as intermittent renewables proliferate, increased interregional transmission capacity “provides resilience and consumer savings during extreme weather events,” the study wrote.  

The study cited an analysis by Grid Strategies which found that during the “bomb cyclone” cold snap in the winter of 2017/18, ISO-NE, NYISO and PJM each “could have saved $30 [million to] $40 million for each gigawatt of stronger transmission ties among themselves or to other regions.” 

Analyses have also projected significant cost benefits of increased two-way transmission capacity between Quebec and the northeastern U.S., with hydropower balancing out intermittent resources and limiting the need to overbuild clean energy.  

One 2021 study found this bidirectional flow could reduce overall power costs by about 5 to 6% on a future grid with high levels of renewables. (See Québec, New England See Shifting Role for Canadian Hydropower.) 

Notably, the nonprofits behind the effort represent both sides of the border; the Acadia Center is based in New England, while Nergica is based in Québec. 

Frédéric Côté, general manager of Nergica, said one of the key goals of the forum is to help projects that address pressing transmission needs to overcome the hurdles that have caused cancellations and delays in recent years. 

Transmission planning historically has occurred “mostly jurisdiction by jurisdiction,” Côté said. “We feel that there is a need to rethink how it is done.” 

“Time is of the essence if we want to achieve carbon neutrality by 2050,” Côté said. “We think we need to bring as many people as possible around the table to put together a road map for the region.” 

In 2023, a coalition of states launched the Northeast States Collaborative on Interregional Transmission, which has since grown to 10 states. (See Northeast States Detail Early Efforts on Interregional Tx Collaborative.) The NGPF is not intended to replace or be redundant with this collaborative, but instead is aimed at engaging a wider set of communities and stakeholders, the organizers said. 

The forum is initially envisioned as three roundtables focused on different themes: environmental justice and community mobilization, interregional planning, and clean energy procurement and markets development. 

Reflecting on the recent struggles of projects like the Twin States Clean Energy Link, Côté called for a greater focus on tangible community benefits, as well as on market reforms to better facilitate bidirectional power exchanges across the U.S.-Canada border. (See National Grid Backs out of Twin States Clean Energy Link Project.) 

“It’s not that easy to envision bidirectional exchanges in the current market state,” Côté said.  

Rob Gramlich, president of Grid Strategies, said there is no “magic bullet” to prevent project cancellations, “but having greater regional buy-in on new lines sure would help.” 

“Ideally, we need the key policymakers that are engaged in that forum to have some high-level conceptual agreement on a plan and a way to allocate the costs,” Gramlich said. 

The forum’s organizers say they hope to hold in-person roundtables over the coming fall or winter and have met with different stakeholder groups to plan and gauge interest. 

“We’re in Phase 1 of really testing ideas and getting input,” Sosland said. “We will then do an internal assessment in early May about whether there’s enough interest and support to expand this into a larger phase.”  

While nothing is set in stone, Sosland and Côté said they’re encouraged by the feedback they’ve received. 

“We’re getting really exciting responses to this,” Sosland said. “If things proceed, we want to be very optimistic about the interest in moving this into an actual forum, actual roundtables and actual discussions.” 

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Calif. Regulators Assess Benefits, Social Costs of Energy Transition

California energy officials are attempting to calculate the “nonenergy benefits” (NEBs) and social costs of decarbonizing the state’s electricity grid. 

This assessment is a provision of California’s Senate Bill 100, which requires 100% of electric retail sales be supplied by renewable and zero-carbon resources by 2045.  

In an April 16 California Energy Commission (CEC) workshop, regulators and advocacy groups dove into the complexities of modeling for and evaluating NEBs, which “represent an array of diverse impacts of energy programs and projects beyond the generation, conservation, and transportation of energy,” according to the CEC.  

“All Californians have a stake in this process as we move forward and envision what the world will look like and think about the impacts on health, air quality, greenhouse gas emissions, and of course, how we think about electricity bills and the Californians who are bearing the cost of the energy transition,” said Alice Reynolds, president of the California Public Utilities Commission (CPUC).  

In February, a collection of state and local organizations, including the Center for Biological Diversity, the California Environmental Justice Alliance and the Local Clean Energy Alliance, petitioned the CEC to adopt an order requiring the integration of NEBs and social costs into resource planning and decision-making processes.  

“The CEC is long overdue in satisfying statutory mandates to consider NEBs and social costs in its decision-making,” the petition states. “Until the agency does, the CEC’s decisions will continue to ignore the local environmental impacts — that fall disproportionately on disadvantaged and other environmental justice communities — of energy production and contribute to leaving the same communities behind in the clean energy transition, risking the overall achievement of SB 100 and other state climate policy.” 

SB 100 requires the CEC, CPUC and the California Air Resources Board (CARB) to issue a joint report every four years. The next report, expected in January 2025, will be the first to formally include NEBs and social costs.  

Decarbonization Will Bring ‘Vast Health Benefits,’ CARB Finds

Integrating analysis of NEBs and social costs into resource planning and SB100 implementation is a collaborative effort, and each agency discussed its anticipated tools and planning methodologies.  

Bonnie Holmes-Gen, health and exposure assessment branch chief at CARB, presented tools used in the board’s 2022 Scoping Plan, which sets a 2045 decarbonization goal, that will be central to analyzing NEBs and social costs, including a health analysis conducted for all rules the board considers.  

Central to the analysis is the “incidence-per-ton” method that assesses the health benefits of emissions regulations and resultant avoided health outcomes, including asthma, cardiovascular problems and death. CARB used this methodology in its Scoping Plan to analyze the impacts of direct and indirect particulate matter and nitrous oxide pollution associated with fuel combustion., It estimated the regulations needed to meet 2045 climate goals would result in $200 billion in healthcare savings, almost 2,000 cases of reduced mortality, thousands of avoided hospital visits and more than 300,000 cases of reduced asthma symptoms.  

CARB used a Climate Vulnerability Metric to identify the economic costs of climate impacts, referred to as the social cost of carbon. The method applies a dollar amount to the long-term damage done by one ton of greenhouse gas emissions in a given year and represents the value of damages avoided by reducing emissions. Using this tool, CARB estimated implementation of the Scoping Plan would avoid $6.5 billion to $23.9 billion in climate damages by 2045.  

“In comparison to the estimated direct costs for the Scoping Plan, this provided a very clear picture of the vast health benefits for action that far outweigh the costs,” Holmes-Gen said.  

CARB plans to apply these tools to the NEB and social cost assessment for the 2025 report.  

CEC’s standard capacity expansion and production cost modeling will produce data that can feed into the nonenergy impacts analysis, as well, said Liz Gill, reliability branch manager at CECs Energy Assessments Division. However, the modeling done so far is at a balancing authority area level, so the data will need to be downscaled. The modeling results also do not include power plant locations.  

“This means that without carefully vetted downscaling, we can’t evaluate, for example, how much reduced generation from gas plant X might impact the air quality and community and why,” Gill said. “So, if you take anything away from today’s workshop, that should be that data granularity is really the primary challenge in determining energy impacts at a community scale for this state-level analysis.”  

CPUC Approach

The CPUC’s Integrated Resource Planning process is central to procuring the clean resources needed to provide societal benefits, said Dan Buch, energy division branch manager at CPUC. Utility code requires the commission to consider certain societal nonenergy impacts in its cost-effectiveness tests, which are another key tool that could be used to analyze NEBs.  

In 2019, the commission authorized a pilot for a societal cost test, which uses values for avoided air pollutants, the social cost of carbon and a social discount rate to identify costs associated with certain resources.  

But using the test did not lead to increases in renewable resources or distributed energy resource (DER) procurement, the presentation reads.  

“The key finding was that using a societal cost test instead of a more traditional test, like a total resource cost test … didn’t actually lead to significant changes in procurement,” Buch said.  

The societal cost adders are similar to the commission’s payments to meet greenhouse gas abatement targets and didn’t change the mix of DER and supply-side resources, he said. And because many clean energy programs and new resources are ratepayer funded, costs must be considered carefully.  

“I think the key here is that prudent investments reduce system costs. Other investments that don’t reduce system costs need to be considered very closely because we are certainly facing some affordability challenges in California,” Buch said. “Things that are driving up utility rates both increase that pressure and make it harder for us to induce electrification decisions among customers.” 

Perspective from Environmental Groups

Instead of relying on ratepayers, Mohit Chhabra, senior analyst at the Natural Resources Defense Council, suggested funding alternatives, such as the general budget, tax revenues or cap-and-trade programs.  

“Higher electric rates mean higher bills. And it also means electricity is more expensive relative to fossil fuels,” Chhabra said. “High rates impact people on the income scale differently.”  

Roger Lin, senior attorney at the Center for Biological Diversity’s energy justice program, has a different take.  

“I’d like to challenge the assumption that DERs that deliver more community benefits and avoid harms increase rates,” he said. “We need to move past pitting public health and the environment against affordability.”  

Rates began to increase in 2013, before the state set official electrification goals, Lin said, resulting in what he refers to as “the big mystery” of skyrocketing prices for power over the past decade.  

Lin also disagreed with the CPUC’s analysis that use of the societal cost test did not change the resource mix. The test, he said, is inherently flawed, because it does not consider the millions of dollars in Energy Savings Assistance program funds available and relies on the assumption that ratepayers will fund everything.  

“The test results and the methodology assume that only ratepayer funds were used and no federal or state subsidies. Of course, [decarbonization is] going to increase rates if you ignore all these subsidies that especially target disadvantaged communities,” Lin said in an interview with NetZero Insider. “Just assuming that other ratepayers are going to foot the bill is incorrect because there are lots of targeted subsidies for those populations.” 

Lin also took issue with the CPUC’s use of a standard value for human life in the test when determining how much an individual would pay to avoid sickness. Because the value is standardized, it doesn’t consider that disadvantaged populations likely would pay less to stay healthy than a wealthier demographic. The test also assumes gas plants, which adversely affect air quality and health outcomes, are not retired.  

Excluding these factors leads to skewed results, Lin said, scoring energy projects highly that are considered cost-effective but have adverse social impacts. 

“We know that the local air quality around power plants is worse … and so if we’re looking for improvements in local air quality, how can we really track those improvements if we’re assuming those pollution sources are still there? And so that’s why they’re like ‘there’s not that much of a benefit,’” he said. “There’s not that much of a benefit because you’re not taking out the thing that poisons people.”  

CEC acknowledged the challenges associated with modeling for NEBs and social costs.  

“I just want to say that this is one of those really difficult and nuanced topics,” said Commissioner Siva Gunda. “It really takes a lot of thoughtfulness in making sure we have a conversation that ultimately benefits the people of California and making sure we uplift every community as we go through our clean energy goals.”