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November 5, 2024

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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.”  

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Wash. Sets Income Levels for Help with Buying or Leasing EVs

The state of Washington has announced financial aid for middle-income residents wanting to buy or lease electric vehicles. “We want to democratize EVs,” said Gov. Jay Inslee (D) at an event April 23 in the Seattle suburb of Tukwila.  

Washington is the first state in the nation to fund electric vehicle leasing for people with modest incomes, said Mike Fong, director of Washington’s Department of Commerce, which will handle the grant program. The program is a way to deal with electric cars’ high costs and assist those who fall under certain income thresholds. 

The legislature set aside $45 million for fiscal 2024-25 for this program from its revenue from Washington’s cap-and-invest program. To be eligible for assistance, an individual or family can earn up to 300% of the federal poverty level: no more than $45,180 annually for a single person or $93,600 for a family of four. 

The new program will provide up to $9,000 in an “instant rebate” program for leasing a new electric vehicle for up to three years. It also provides $5,000 for buying a new electric vehicle or leasing one for two years. The program also provides $2,500 for buying or leasing a used electric vehicle. 

The state estimates that four electric vehicle models will lease for less than $100 a month, while the most leased gas internal combustion cars cost roughly $500 a month. 

Inslee said: “We know once people buy these vehicles, they stick with them.” 

“Transportation is the biggest contributor to greenhouse gas emissions and harmful air pollution,” Fong said. “It is important that people who live in our most impacted communities, which tend to be urban and lower-income, have access to cleaner transportation options, including the choice of EV ownership. These rebates can help many more people all across the state buy or lease an EV.” 

According to the Department of Commerce, anyone interested in the program would go directly to an EV dealer to learn about offers available in the state’s instant rebate program. If the consumer qualifies under the income requirements, the dealer “deducts the applicable rebate amount from the cost of the lease and then applies dealer, state and local fees to arrive at the total lease amount.” There’s no sales tax because EVs qualify for the state’s zero-emission vehicles exemption. 

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ERCOT Works to Address Loss of San Antonio Units

ERCOT is searching for alternatives to replace capacity that will be lost with the planned retirement of three gas-fired units near San Antonio. 

The Texas grid operator issued a market notice April 22 saying it plans to issue a request for proposals for must-run alternatives (MRA) to avoid a more expensive reliability-must-run (RMR) contract with CPS Energy. 

“Any decision on whether to enter into an RMR or MRA service agreement must evaluate the costs and benefits of the service,” ERCOT said. 

The San Antonio municipality told the ISO last month that it planned to “indefinitely suspend operations” in 2025 of three gas-fired units at its V.H. Braunig facility. The three steam turbines, dating back to the late 1960s, have a combined summer seasonal net maximum sustainable rating of 859 MW. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Spokesperson Milady Nazir said in an emailed statement that the units’ retirement is part of the municipality’s board-approved generation plan and that the units were nearing their “operational end of life.” 

However, ERCOT’s reliability analysis identified “performance deficiencies” without the CPS resources on the system and determined the power plants are needed to support system reliability. In a filing with the Texas Public Utility Commission, the grid operator’s staff said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions. 

ERCOT has asked the PUC for a good-cause exception from its protocols’ timeline for RMR and MRA deadlines because of resource constraints. 

“We would prefer to come up with a different timeline that still meets all the technical requirements in the protocols but gives us a little bit more time to get that RFP out and work with CPS on what a budget might look like for those units,” General Counsel Chad Seely said at the Board of Directors’ Reliability & Markets Committee. 

“We will continue to have collaborative discussions with ERCOT during their review process,” Nazir said. 

Seely said the ISO’s exit strategy for the RMR will “ultimately be a transmission solution.” 

“Now, if there are other resources that could fulfill an MRA, that would give us the equivalent, then we can substitute for those, and that’s part of the process here,” he told the R&M committee.  

The board on April 23 approved the $435 million San Antonio South Reliability II project that addresses issues south of the city. It approved another reliability project last August, proposed by CPS Energy at a projected cost of $329 million, that addresses thermal overloads in the area. (See “$435M San Antonio Project OK’d,” ERCOT Technical Advisory Committee Briefs: April 15, 2024, and “Members Endorse $329M CPS Energy Reliability Project,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.) 

An RMR contract would be ERCOT’s first since 2016. ERCOT entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Ending Greens Bayou RMR May 29.) 

Because RMR and MRA determinations support ERCOT’s transmission reliability, costs incurred under either agreement are shared by all market participants that serve load. Costs are allocated on a load-ratio basis.

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MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle

CARMEL, Ind. — MISO announced April 24 that 123 GW of new generation spread across 600 applications are vying to enter its generator interconnection queue under the 2023 cycle.   

The 2023 intake, composed nearly exclusively of renewables and storage facilities, is almost 50 GW smaller than the 2022 application cycle MISO has been processing. MISO said while the number of proposed megawatts is still “significantly higher than historical averages,” 2023’s submittals were tempered due in part to its new, FERC-approved suite of tougher conditions on entrants.  

Of the 123 GW of 2023 entrants, MISO said 115 GW (93%) represent wind, solar, storage or a combination of renewables and storage facilities. New solar projects account for 50 MW, storage projects total 29 GW, wind projects clock in at 19 GW, and hybrid renewable and storage projects about 17 GW.   

MISO said if all the 2023 submittals are certified and accepted, the MISO queue will grow to 348 GW. 

MISO required developers of the latest submittals to pay double in entrance and staged queue study fees, be subject to automatic and escalating penalty charges, and confirm they’ve obtained land for projects. The RTO had delayed opening its 2023 queue application window until March to obtain FERC approval to implement the new requirements. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)  

MISO said its stricter requirements will allow for quicker network upgrade studies because it cuts down on the number of speculative projects entering the queue and then dropping out. It said it expects “higher-quality and more viable projects entering the queue.” 

“Although these changes have resulted in a reduction from the previous cycle, it still represents a large number of projects for the team to study,” Director of Resource Utilization Andy Witmeier said in a press release. “We will continue working with our stakeholders to refine the queue process.” 

Witmeier also pointed out that MISO is awaiting about 50 GW in approved generation projects that have yet to complete construction due to “financing, supply chain issues, delays in permitting and power purchase agreement negotiations.” (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.)  

At an April 24 Planning Advisory Committee meeting, MISO staff said the RTO still plans to file again to implement an annual megawatt cap on project submittals to the interconnection queue. FERC rejected MISO’s first attempt to cap its queue entries annually based on a formula. (See MISO to Try Again for Interconnection Queue MW Cap, Open Window for 2023 Requests.)  

The RTO has said annual queue entries as large as 2022’s 171 GW aren’t sustainable for a system that peaks at about 125 GW in the summer.  

At the Gulf Coast Power Association MISO-SPP conference in March, MISO’s Scott Wright said the RTO worries about the queue “getting killed by volume,” where it’s nearly impossible to process projects because the queue is in essence “sabotaged” by scores of low-quality projects that aren’t fully fleshed out before being entered.

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Forum: Innovation Key to Advance NJ Offshore Wind

UNION, N.J. — Innovation and in-state project development by engineers and thinkers will be key to New Jersey’s offshore wind future as the state advances its groundbreaking initiative to create an offshore power center that can connect to homes and businesses onshore, according to speakers at the Wind Institute Research Symposium. 

The extensive scale of the task, and the lack of history in creating such a major transition, will mean the work of problem-solving engineers, entrepreneurs and academics will be critical to overcoming the expected and still-unknown hurdles, speakers told the audience at Kean University on April 12. 

Leading a panel on OSW research and collaboration, Kris Ohleth, executive director of the Special Initiative on Offshore Wind, said that after working for 25 years in the sector, she sees the state at a critical juncture, sitting on the cusp of bringing OSW to reality. 

“We said 20 to 25 years ago, ‘OK, we know these are going to be the challenges, and once we get through this development phase of offshore wind and we move to this phase of implementation that we are at today, someone’s going to figure it out,’” she said. “And those someones are you — you folks sitting here today.” 

Present in the audience, and among those outlining their work, were many of the 40 participants in the institute’s fellowship program started last year. Among the topics tackled by fellows, and showcased at the forum, were the socioeconomic and policy implications of OSW projects, how to secure public support, the development of a weather station that could predict wind energy generation, and how to make more effective and quieter turbine blades. 

Unknown Future

New Jersey is seeking to revitalize its OSW sector after Danish developer Ørsted in October withdrew its two projects planned for the Jersey shore: Ocean Wind 1, the state’s first OSW venture, and Ocean Wind 2, one of two projects awarded in the state’s second solicitation. 

The withdrawal left the state with just one active project: Atlantic Shores. The Board of Public Utilities approved two more Jan. 4: Leading Light Wind and Attentive Energy Two. If they come to fruition, the three projects would have a capacity of 5,252 MW, a major step toward the state’s goal of 11 GW by 2040. But getting there is no easy task, Tim Sullivan, executive director of the New Jersey Economic Development Authority, told the group. 

“This is not like flipping a switch and it’s going to happen,” he said. “There are big known unknowns that we are counting on innovation to bail us out of, of how we are actually going to deliver on the promise of offshore wind. 

“No one’s ever done this before. No one’s ever put an 11-GW power plant off the coast of a major industrial state and plugged it into a grid that is not particularly new and made it come out of people’s houses,” said Sullivan, whose agency helped organize the event and provides financial support for OSW projects. “We don’t know exactly how that’s going to work. You all, and others around the world, are working on those challenges.” 

Public Concern

Key to the success of the projects will be the public reaction as construction gets underway and the cost of transitioning to coastal wind generated power becomes clearer. 

The most vigorous opposition to the projects has emerged from the commercial fishing industry, local residents and tourist businesses, who fear that turbines in the ocean will damage the local quality of life. Several presenters at the symposium focused on the issue and where the opposition stemmed from. 

Dylan Irmiere, a Stockton University student and a fellow of the wind institute, said that in the two public opinion surveys he commissioned and conducted in New Jersey as part of his research, 46% of those polled — including residents in the shore area and the rest of the state — had no knowledge at all of the wind projects, and 41% had slight to moderate knowledge of them. 

The research showed positive public support among respondents for OSW as a solution to fight climate change, he said. Only one in five believed there would be environmental harm, and about 58% thought the projects would help the environmental, while about 60% said they believed the farms would help the economy. 

However, when the respondents were given additional facts — what Irmiere called “surface-level knowledge” — about project distance from shore, the predicted economic benefits and the background of developers, only 33% said they wanted the projects to continue, and nearly a quarter said they did not support the continuance of the projects. 

The fact that nearly a quarter of people had concerns after the intervention “could mean that they are still lacking sufficient information to form an educated opinion,” Irmiere said. He added that even after survey respondents were given information about federal actions to protect marine animals, 31% were neither satisfied nor dissatisfied, suggesting they “could need” more information. 

“Learning that providing information to respondents about the environment and the economy helps to form sentiments of offshore wind gains should be something that companies developing these projects, as well as the governments in local communities, focus on,” he said. “To encourage the public to think more positively, sentiments about offshore wind should be constructed in a way that demonstrates their effectiveness on the environment and the economy.” 

The surveys also showed how turbine distance from the shore can affect public support: While about 33% agreed that three miles offshore was a “reasonable distance” to site turbines, that figure grew to 55% for 12 miles and 59% for 20 miles. 

Aparna Varde, associate professor in the Montclair State University School of Computing, said she and a graduate student, Isabele Bittencourt, studied social media posts about the projects. Their work focused on sentiment analysis, looking at whether the prevailing sentiments expressed are positive or negative to offshore wind; and topic modeling, to see what issues were raised most in posts about the wind projects. 

The pair used three different methods of analysis, and all three found that between 37 and 40% of the comments were positive and between 26 and 36% were neutral, Varde said. Between a quarter and a third of the posts were negative, according to her presentation. Still, the positive slant to the comments was far from overwhelming, she said.

Tracking Mammals Underwater

The impact on marine life of wind farms emerged as a potent issue early in 2023 when a series of dead whales washed up on New Jersey shores. Opponents have raised concerns that preliminary work on the wind farms contributed to the deaths, even though no construction has started and federal investigators have found no connection between the deaths and the wind projects. 

State officials told the symposium they are taking steps to minimize any harm. Offshore wind developers pay a fee of $10,000/MW to the state Research and Monitoring Initiative (RMI), which to date has been awarded $65 million for research projects, according to speakers from the New Jersey Department of Environmental Protection and the BPU. The RMI has awarded $13 million of that money to research projects, including one that sends “ocean gliders” into the sea to collect data on water temperature, and the level of chlorophyll and pH in the water. 

“These gliders are autonomous mobile platforms that are outfitted with a suite of sensors that collect really high spatial and temporal resolution data on water chemistry and physical ocean processes, like the seasonal formation and breakdown of the cold pool,” said Caitlin McGarigal, a research scientist at the DEP, referring to the seasonal stratification of cooler water close to the ocean bottom. 

“This just sort of exemplifies the type of data that’s being collected on this project and how these data can be really useful for understanding wildlife movement and behavior,” she said. 

Another RMI-backed project is using acoustic telemetry — “like an underwater E-ZPass” — to set up receiver listening stations that can rack species that have been tagged, she said. A third project is helping the National Marine Fisheries Service to expand a project that uses aerial tracking from planes to study the movement of whales in New Jersey waters, she said. 

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SPP Markets and Operations Policy Committee: April 16-17, 2024

Staff Reveals Error in GI Queue Studies; Clearing Backlog Still on Course

AURORA, Colo. — SPP staff publicly alerted stakeholders last week that it failed to conduct a tariff-required analysis of several generator interconnection queue study clusters as they reduced the backlog of GI requests dating back to 2017. 

SPP’s Casey Cathey, senior director of asset utilization, quoted his late father, a salesman, as he broke the news some members already were aware of during the Markets and Operations Policy Committee on April 16. He said SPP discovered it “inadvertently” failed to conduct a contingent facility review for five clusters, beginning with the 2017-001 grouping through the 2020-001 collection. 

“[My father] would say, ‘You don’t lose customers by making mistakes; you lose customers in how you handle those mistakes,’” Cathey said. “We made a mistake. That’s just plain and simple.” 

SPP plans to handle this mistake using two processes dependent on the cluster study’s progression. Once SPP has determined which interconnection requests in the affected clusters are contingent on previously assigned network upgrades, it said generator interconnection agreements will have to be amended to include the contingent facilities. 

Until then, GI requests in the affected clusters that were not identified by SPP during the study process may be contingent. Those projects may be subject to limited operations until the contingent facilities are in service. Additionally, requests in the clusters in question could be assigned the cost of those facilities should higher-queued GI requests not build them. 

“This is a big deal, and it’s a big deal with a number of tentacles to it,” the Advanced Power Alliance’s Steve Gaw said. “When this first came out, it really did send shock waves through the developer community. We are still in the mode of dealing with, ‘What does this do?’ 

“What we want we don’t know yet, and what’s going to be yet to develop is what the ultimate impacts are to the generation that’s in this queue, and to the investments that have already occurred,” he added. 

Steve Gaw, Advanced Power Alliance | © RTO Insider LLC

The grid operator includes clearing the GI backlog of all requests submitted through 2022 by the end of the year as a priority for 2024. According to a timetable, it would post the last contingent facilities remedy, for the 2020-001 cluster, in August. The active queue contains 421 requests for 87 GW of capacity; it numbered 1,139 requests for 221 GW when the backlog-clearing effort began.

“We’re still very much pushing to make that goal by the end of this year,” Cathey said. “We have to resolve this. We recognize how important this is and we have to resolve that in a way that minimizes the impact to the customers.” 

He said SPP will post contingent facilities cluster study reports and amend GIAs as required. Developers with GI requests should review all their projects, especially those in affected study groups, he said. Those nearing commercial operating dates or subject to 0 MW due to contingent facilities can request the RTO perform a limited operation system impact study (LOSIS), with a group LOSIS offered to those in service or expected to be in service within 18 months. 

“This is a serious error and we’re working with the developer community to come up with a very tight remedy plan to rectify this,” Cathey said, adding that he welcomes other novel ideas to accelerate the plan. 

Record Tariff Changes?

Members took up 26 tariff revision requests during the two days, leading MOPC chair and ITC Holdings’ Alan Myers to posit that the number may be a record. The committee took no action on one of the RRs, but the other revisions and voting items passed with an average 96% approval. 

A proposed revision incorporating western entities into SPP’s resource adequacy process when they join the RTO’s markets failed initially, securing only 53.4% of approving votes. When the motion’s language was amended to clarify that deliverability across the DC ties would only include firm transmission service, the motion passed with 83.1% approval. 

MOPC also delayed action on RR620, which would implement SPP cost-allocation policies for Joint Targeted Interconnection Queue (JTIQ) projects. However, the RTO’s staff, transmission owners and SPP’s JTIQ partner, MISO, have been unable to reach consensus over the rate template in pursuit of a more efficient “direct billing” approach. The committee agreed to a conference call April 26 to wrap up the tariff revision, but the meeting was cancelled April 22. Staff said the work to finalize RR620 is ongoing. 

SPP and MISO have agreed to assign 90% of the JTIQ portfolio’s $1.06 billion in costs for its five projects to generation. Load will cover the remaining 10%. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.) 

The committee endorsed five other RRs that, if approved by the board, would:  

    • RR600.8: Add an incremental market-efficiency use charge to provide revenue offsetting incremental DC tie operations costs due to their market dispatch. The charge would be levied proportionally to all market participants’ activity, including those with export and virtual transactions. 
    • RR605: Define an authorized outage and criteria, add requirements for resources’ availability during both the summer and winter seasons (unless on an authorized outage), help load-responsible entities and generation owners better understand when to submit resource adequacy (RA) capacity when providing workbooks to meet the RA requirement. 
    • RR608: Allow new generation resources to operate with fewer restrictions during seasons where interconnection studies did not identify transmission constraints prior to the completion of all network upgrades, while still restricting those generators in seasons where interconnection constraints were identified. 
    • RR612: Modify the multiday economic commitment to allow long-lead resources to receive market commitments for purposes beyond reliability. 
    • RR616: Ensure any outage not approved by the SPP balancing authority and not an outside management control event is accounted for in performance-based accreditation (PBA). 

MOPC also approved separate measures imposing resiliency options and correlated changes to the 2025 Integrated Transmission Plan and removing the voltage stability analysis from the 2024 ITP study. It also endorsed a price-formation policy to dispatch resources based on the true obligation and price the system using the obligation without the impact of the load shed and emergency pricing assistance. 

SPC OKs Forecasting Task Force

Meeting after MOPC, the Strategic Planning Committee endorsed staff’s recommendation to create a task force to improve regional load forecasting that tends to come up short.  

Staff said even its lowest scenarios for peak load in winter forecasts exceed members’ load expectations for resource adequacy. Summer load forecasts during ITP submissions exceed the lowest growth assumptions and remain below trends for more rapid growth, they said. 

“Can we be better?” SPP’s Cathey asked, drawing responses of agreement from several members. “From a regional perspective, it’s 100% driven by the responsible entities and populated by members, so it’s fully through member input. The question is, how can we put a little bit more attention to this to get a little bit more accuracy in the use cases and providing better data with changing, unconventional loads?” 

Strategic Planning Committee observers are separated from the rest of the committee. | © RTO Insider LLC

Pointing out that some members have more sophisticated tools than others, “depending on the size of their shop,” Cathey said staff has reached out to some members as well as SPP’s fellow grid operators to gather data for the task force. He said SPP intends to keep the task force’s membership small, but open, and focused on employees with planning responsibilities.  

Cathey said staff believes defining improvements to regional planning would take eight months. He promised a checkpoint at year’s end, with some long-term solutions handed to other stakeholder groups. 

The SPC meeting was conducted with a somewhat unusual seating arrangement. The committee’s leadership headed a U-shaped arrangement with SPP’s rostered members. Behind the main table, another U-shaped arrangement gave interested onlookers a view of the backs of the committee leadership’s heads. 

“Sorry, I have worked my way up from coach in the back,” quipped SPP’s Robert Fox, director of enterprise architecture, as he belatedly joined the main table to comment. 

Last MOPC for Dowling

The MOPC meeting was the last for Midwest Energy’s Bill Dowling, who is retiring after 39 years sitting in the committee and other SPP meetings — or, as Midwest’s vice president of engineering and energy supply said in referring to the number of years he has spent with the RTO, “a lot.” 

Myers began the meeting by singling out Dowling for recognition. Like Myers, Dowling has served as the committee’s chair. 

“I’ve gotten to know a lot of really great people,” he said. “It’s been a pleasure working with some really smart people. It makes me look good.” 

Committee Consents to 19 RRs

MOPC’s unanimous approval of the consent agenda endorsed 19 RRs, 10 of which will go to the board for further consideration:  

    • RR555: Adds requirements to the operating criteria addressing FERC cold-weather recommendations. 
    • RR600.7: Integrates western entities seeking RTO membership under SPP’s terms and conditions with updates that include a DC tie access charge. 
    • RR600.9: Adds a separate balancing authority area on the western side of the DC ties to the SPP BA. 
    • RR600.10: Awards auction revenue rights and transmission congestion rights to the alternating current portion of transmission service that cross DC ties between the Western and Eastern Interconnections. Settling the rights will occur in two stages, with the AC portions settling in the respective interconnection.  
    • RR600.11: Renames the tariff’s Attachment AN to Addendum 1 and adds language specific to western entities joining SPP as members of the West BAA.  
    • RR600.12: Includes a separate BAA on the western side of SPP’s DC ties and other necessary market design clarifications adding policies necessary to integrate western parties into SPP. 
    • RR600.13: Bases some rates for point-to-point and network service on the western side of the DC ties and the associated revenue distribution on the amount of annual transmission revenue requirement specific to the facilities in an interconnection. This accommodates Western Area Power Administration’s Upper Missouri and Rocky Mountain Region zones, which have facilities in both interconnections. 
    • RR600.14: Adds language clarifying West DC ties as constraints, similar to other transmission constraints that are part of the market power test and frequently constrained areas validations. 
    • RR600.16: Revises contract services agreements with WAPA-Upper Great Plains by removing language related to the Western Energy Imbalance Service market and narrowing the list of WAPA-UGP facilities to only those that are and will remain in the NorthWestern Energy BAA. 
    • RR607: Implements the Regional State Committee’s change to the tariff’s safe harbor provisions, from 125% to 100% plus the higher of summer or winter season planning reserve margin plus 10% (but not less than 125%). 

Nine other endorsed RRs don’t require board approval: RR590, RR596 , RR604, RR609, RR613, RR614, RR617, RR624 and RR625.