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November 19, 2024

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SPP Membership Elects Solomon, Dimitry to Board

LITTLE ROCK, Ark. — SPP’s membership elected Stuart Solomon and Irene Dimitry to three-year terms on its independent Board of Directors during last week’s Annual Meeting of Members. 

Current board member Liz Moore also was elected to serve a second term, having joined the board in 2020. All three selections are effective Jan. 1. 

Solomon, who has more than 30 years of utility experience, is a familiar presence among SPP members. He served on the Members Committee during his 14 years as Public Service Company of Oklahoma’s president before retiring from American Electric Power in 2019 as senior vice president of generation services. Solomon was at Central and South West Corp. when the company merged with AEP in 2000. 

Stuart Solomon | © RTO Insider LLC

“One hundred percent he knows what he’s getting himself into, which I love about Stuart,” CEO Barbara Sugg said during the board’s Oct. 31 meeting. “Yet, he’s still excited about continuing to talk about [SPP members] and anything else.” 

“It’s a very important time of transition in the electric utility industry, and SPP is well positioned to lead the ongoing evolution of the industry,” Solomon said in a statement. “I’m excited to be part of such a dynamic and forward-thinking organization during this time.” 

Dimitry retired in 2020 as vice president of renewable energy at DTE Energy, where she led the launch and daily operations of the company’s renewable energy business. She has more than 26 years of utility experience. 

“The clean energy transition will bring many changes and innovations over the next few years,” Dimitry said. “I look forward to working with management and stakeholders as SPP’s regional role grows and evolves.” 

Solomon and Dimitry will replace long-time directors Josh Martin and Larry Altenbaumer. The two, who have almost 38 combined years on the board, are retiring at the end of December. (See “Board Search Underway,” SPP Board/Members Committee Briefs: July 24-25, 2023.) 

The board recognized Martin and Altenbaumer with honorary resolutions and standing ovations during the meeting, along with a dinner where they were joined by former SPP CEO Nick Brown and former director Graham Edwards. Brown and Edwards left during the COVID-19 pandemic and did not receive honorary fetes. 

SPP’s membership also approved 16 nominees to the 24-person Members Committee. All but two were incumbents; Google’s Betsy Beck and Evergy’s Kayla Messamore will begin three-year terms in January representing the large retail customer and investor-owned utility segments, respectively. 

The small retail customer segment’s seat remained vacant. 

Texas’ McAdams to Lead RSC in 2024

The Regional State Committee, comprised of state regulators from SPP’s footprint, elected its leadership for 2024 by approving a committee’s recommendations in a voice vote. 

Texas’ Will McAdams will serve as the RSC’s president. He already chairs SPP’s REAL Team, in addition to his day jobs on the Public Utility Commission and helping manage the family farm near College Station. 

Referencing McAdams’ leadership in guiding the REAL Team as it assesses SPP’s current resource adequacy construct and makes policy recommendations, Sugg said, “If we’ve got the will, we can get this thing done, and I think we’ve got Will McAdams. 

“I can’t commend him enough,” she added. “From the conversations I’ve had with people who were and from what I observed from somewhat of a distance. He just did a remarkable job and I’m so thrilled that we had his leadership involved in terms of moving this thing forward.” 

Minnesota’s John Tuma will serve as the RSC’s vice president and Nebraska’s Chuck Hutchinson as its secretary and treasurer. 

The RSC also considered two motions related to SPP’s safe harbor criteria used to determine which project costs should be borne by the load-serving entities (LSEs) making long-term transmission service requests (TSRs). The safe harbor exempts LSEs from upgrade costs when a TSR meets the aggregate studies’ waiver criteria, which include: 

    • Wind generation not exceeding 20% of designated resources; 
    • A minimum five-year term for designated network resources TSRs; and 
    • Designated resources not exceeding 125% of forecasted load. 

The commissioners rejected the Cost Allocation Working Group’s recommendation to eliminate the 20% wind criteria but approved its proposal to increase the resource limit from 125% to 100% plus the higher of summer or winter seasonal planning reserve margin plus 10%. 

Future RSC Members Observe

Several potential future RSC members joined the table for an up-close look at how SPP stakeholders make the sausage: Colorado’s Eric Blank, Utah’s Thad LeVar and Arizona’s Kevin Thompson. 

Their three commissions would be eligible to appoint representatives to the RSC as SPP’s RTO West is stood up and begins operations in 2026. The grid operator uses an outreach program when it anticipates additional states will become part of the footprint. 

Mary Throne, who chairs the eligible Wyoming Public Service Commission, also has attended SPP meetings this year. The Wyoming commission is eligible to join the RSC. 

Calling RTOs a “significant milestone in the western United States,” LeVar said, “I appreciate the chance to watch this mature and useful process that happens here and I look forward to the tariff development that will happen between now and implementation of RTOs.” 

Thompson said Arizona is determining whether to join SPP’s Markets+ “RTO-lite” day-ahead market or CAISO’s Extended Day-ahead Market (EDAM).  

“There’s a lot to learn,” he said. “I’m here to learn, I’m here to absorb and to take in everything that I can to make sure that [at] the end of the day, our utilities are protected and that our consumers are protected.” 

Blank, who chairs the Markets+ State Committee comprised of western commissioners, jokingly suggested a bylaw change, saying he would prefer a president’s title.  

“I covet your title,” he told RSC President Andrew French. 

Naturally, almost every speaker then addressed the committee’s leader as “President French” for the meeting’s duration. 

Lucas, Rew Update Stakeholders

Antoine Lucas, SPP’s markets vice president, said during the quarterly stakeholder reports that the Integrated Marketplace set new records for maximum load (56.18 GW on Aug. 21), bettering the previous high of 53.24 GW set in July 2022, and renewable energy production (25.02 GW on Sept. 4). Wind accounted for 51.69% of the fuel mix at its peak Sept. 4. 

Bruce Rew, senior vice president of operations, said load exceeded the 2022 record during 24 hours the week of Aug. 21.  

Day-ahead prices and real-time prices both increased more than 35% from the second quarter to the third, Lucas said, a result of increased fossil fuel generation during late-summer calm days. Day-ahead prices were up from $24.17/MWh to $33.13/MWh and real-time prices went from $23.11/MWh $31.26/MWh. 

The Marketplace has 331 participants. 

Rew said SPP has received commitment letters from all nine utilities and Western Area Power Administration regions who want to be in SPP RTO West when it goes live, targeted for April 1, 2026. The commitment obligates them to reimburse SPP for development expenses if membership agreements are not executed in March 2026. 

The western expansion will affect SPP’s existing members in the Eastern Interconnection as changes will be made to the settlements system and all market participants will have to go through some activities, Rew said. He expects about 15 revision requests will come before the board and RSC in January and April. 

Lucas, who is leading the Markets+ development, said the project is on schedule to meet its target date, but that staff and stakeholders are working to mitigate issues that could cause delays. The project team plans to vet funding proposals with the Finance Committee in February. 

“We’re spending more of our time focusing on areas where there are certain unique areas of western market operations that need slightly different market design to what we have here in the east,” Lucas said, a nod to greenhouse gas restrictions, congestion rent allocation and mitigation pricing for hydro storage. 

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Nonprofits Attempt to Force a More Transparent TVA IRP Process

Several nonprofits are calling on the Tennessee Valley Authority to make its integrated resource planning process more transparent as the federal utility charts its resource mix over the next 25 years.

Energy Alabama, Appalachian Voices, Southern Alliance for Clean Energy, Center for Biological Diversity, Vote Solar and Green Workers Alliance submitted a motion to intervene this week in TVA’s 2024 integrated resource plan and environmental impact statement. They pressed the TVA Board of Directors to direct TVA to hold public hearings, create a more open process and let stakeholders sound off on the resource planning study.

The groups said TVA’s IRP will “influence reliability, electricity bill affordability, air and water quality, and regional jobs over the next two to three decades.” They noted that unlike most utilities, TVA’s IRP isn’t regulated by a public service commission and impacted stakeholders aren’t permitted to participate in the process unless “hand-selected” by TVA to join its 24-member IRP working group. The nonprofits said it remains unclear how an interested party can approach TVA to express interest in serving on the working group. They also said it appears the IRP working group simply comments on plans already under development by TVA, with no indication the group offers any meaningful alternatives to generation plans.

“TVA’s IRP and [environmental impact statement] process is not transparent. There is no publicly available list of working group members. Agendas are not posted before meetings. There is no public comment opportunity at working group meetings, nor are these meetings open to the public. To the extent that information is made available to the public, such information consists of perfunctory summaries of decisions made, rather than the data and models that are used in the development of initial and final energy resource strategies and scenarios,” the nonprofits wrote in the motion.

TVA anticipates releasing its IRP sometime next year. It last conducted an IRP in 2019.

The federal utility issued a notice of intent for its 2024 IRP in mid-May, followed by a 45-day public comment period (PPLPWR-11-2023). The nonprofits criticized TVA for imposing multiple, overlapping comment periods on environmental impact statements for key projects that will factor into the IRP, including a guidance analysis for solar and battery additions, a study on the Kingston Fossil Plant retirement, a study to evaluate increasing pumped storage hydropower capacity and an evaluation of the planned, 900-MW, natural gas-fired Cheatham County Generation Site.

The groups also said it was inadequate for TVA to hold just two limited participation scoping meetings in late spring on the IRP where the public was permitted only to ask “clarifying questions.” They said TVA’s timeline doesn’t account for public comment on its resource strategies and scenario modeling, and that modeling already may have begun or will begin soon.

“TVA’s reluctance to adopt a public Integrated Resource Plan process is truly a shame,” Vote Solar Regulatory Director Jake Duncan said in a press release accompanying the motion. “Having worked in IRPs in other states, I’ve personally witnessed the transformative power of a public process, which not only enhances outcomes but also provides an opportunity for utilities to embrace clean energy and address energy justice concerns, benefiting everyone.”

“Advocates are asking for an open and transparent planning process, including bare-minimum standards for public input that are available in IRPs at similar-sized utilities,” Appalachian Voices’ Bri Knisley said. “The TVA board can and should call for a public hearing and allow input and analysis from any relevant outside experts who wish to provide input in the IRP.”

Gaby Sarri-Tobar, energy justice campaigner at the Center for Biological Diversity, said by “concealing” its long-term planning, TVA is failing its customers.

“As energy prices go up and extreme weather looms, there’s absolutely no excuse for TVA to keep people in the dark about plans that will affect their lives for decades. These folks are paying TVA’s bills, and they live with the health and safety costs of the fossil fuel status quo. It’s insulting to exclude them from the planning process,” Sarri-Tobar said.

TVA Maintains IRP Process is Transparent

TVA, however, insists its IRP procedure is already “fully transparent,” with stakeholder engagement a critical piece of the process.

Scott Fiedler, of TVA’s media relations team, said the TVA IRP working group is a “diverse” stakeholder group and that TVA updates the public on its IRP process through meetings of the TVA board and its Regional Energy Resource Council, which is composed of regional governmental representatives, academics and consumer advocates.

Fiedler noted that council meetings are open to the public, with the next occurring Nov. 7 in Tupelo, Miss. He said that will be followed by a TVA board listening session and TVA board meeting — also in Tupelo — Nov. 8 and Nov. 9, respectively. Fiedler also said TVA is planning to host another public webinar on the IRP in December.

Finally, Fiedler said TVA will again collect public opinions in spring when it releases its draft IRP and environmental impact statement. He said TVA will plan “a number of public meetings and other engagements to share those drafts and have opportunities for the public to provide feedback.”

“Bottom line: TVA is fully transparent, and we encourage the public to get involved in how their energy is generated. Together, we can build an energy system that is low cost, reliable, resilient and sustainable that will continue to drive jobs and investment into our region and power the new clean economy,” Fiedler said in an email to RTO Insider.

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New York Seeks to Unlock Geothermal Potential for Buildings

OSSINING, N.Y. — This Westchester County village will be the first place in the state to take advantage of a newly enacted law that expands the accessibility and affordability of geothermal energy. 

Ossining is making geothermal energy the centerpiece of a mixed-used building on a 3.4-acre remediated brownfield site once used to turn coal into manufactured gas. The project will benefit from a law co-sponsored by Sen. Pete Harckham (D) (S6604) that exempts closed-loop geothermal boreholes from the state Oil, Gas and Solution Mining Law. 

Before S6604, which Gov. Kathy Hochul (D) signed on Sept. 21, geothermal boreholes deeper than 500 feet were subject to the same regulations as oil and gas wells. The law’s proponents said the regulations added unnecessary costs and complexities to ground-source heat pump (GSHP) installations, which have little environmental impact because they do not involve injection into or extraction from the ground. 

“We often make technical changes to laws in Albany, and people don’t necessarily see the tangible results, but today we have a very visible example of how one of those technical fixes is going to really revolutionize geothermal,” Harckham said at a Nov. 1 press conference at the site of the project, which will provide heating and cooling to 109 units in a mixed-use building that includes affordable housing. The project will be drilled by Dandelion Energy, a Northeast geothermal supplier, in partnership with the New York Geothermal Energy Organization (NY-GEO) and ZDF Geothermal. 

Backers said the exemption from the mining law will cut costs, increase geothermal efficiency and make GSHPs possible in more places by limiting the footprint needed for drilling boreholes. The previous regulations applied on a per-well basis, adding costs and permitting barriers. 

Heather Deese, senior director of policy and regulatory affairs at Dandelion, told NetZero Insider that S6604 “is one of the many steps needed to unlock the role that geothermal can play.” She said it allows Dandelion “to keep the cost of the drilling for a home geothermal installation as low as possible, because now we can drill one deeper hole for the ground-loop piping, rather than two shallower holes.” 

Shallow systems also tend to underperform compared to their deeper projects that can tap higher sources of Earth heat. 

“We can now use many more sites, particularly urban sites, and it will be much more cost effective,” said Harckham. “Before, drilling [a geothermal well] below 500 feet, all of the sudden, qualified you as an oil or gas well, and inherent with that were a host of financial obligations and permitting and reporting requirements. But now we will be able to take advantage of going beyond 500 feet for geothermal, opening up many, many more projects.” 

Drilling Down

The sponsors project the legislation could reduce the cost of decarbonization by about $900 million by 2030 and another $9 billion between 2030 to 2050. 

The Climate Leadership and Community Protection Act calls for a 40% reduction in building emissions by 2030 and the electrification of 85% of homes and commercial spaces by 2050. The Climate Action Council’s Scoping Plan, which laid out the roadmap to achieve CLCPA goals, says New York must install 250,000 electric heat pumps — including air- and ground-source units — annually to meet the mandates for 2030. 

“Tapping into the potential of geothermal energy is critical to advancing New York’s transition to cleaner energy sources,” said Basil Seggos, commissioner of the Department of Environmental Conservation. 

Tom Staudter, director of communications for Harckham, said that residential projects could save approximately $3,000 per job because they only need to drill one borehole versus several. For commercial buildings, he said the savings will be around $6 per square foot of floor space, if not more. He said the law will enable about 50% of commercial buildings to transition to geothermal systems; many previously were not able to transition because of cost concerns or a lack of space for multiple boreholes. 

Staudter said many in the geothermal industry have been reaching out to Harckham’s office since the bill was signed. “They are ready to expand markedly because of the new law,” he said. “The transition to geothermal energy systems will increase exponentially, as more consumers and developers learn about capabilities, savings and ease of implementation.” 

Installers say a geothermal heat pump for a 2,000-square foot home can cost between $15,000 and $38,000, double the price for a conventional HVAC system. They also estimate that drilling to install a GSHP costs about $5 to $40/foot. Total costs average between $4,000 to $8,000/ton installed. (One ton of refrigeration equals about 12,000 BTU/hour.) 

Households switching from a fuel oil furnace to a geothermal system can save an average of 53% on their annual energy bill, or almost $1,900 a year, according to Dandelion. 

Benefits & Barriers

Geothermal energy, one of the oldest forms of green power, dates back at least 10,000 years. Its first commercial usage was in Arkansas around 1830. The technology involves drilling vertical boreholes and inserting a closed-loop piping system filled with heat-conductive fluid that exchanges heat with the earth to either heat or cool a building. 

Geothermal energy and GSHPs offer numerous environmental, health and economic advantages over fossil fuel systems, but high costs, geographic limitations and a shortage of skilled labor have thwarted widespread adoption. 

The International Energy Agency says geothermal heat pumps have been growing at 3% per year in the U.S., with more than 1.7 million units installed. About 40% of installations are residential; the other 60% are commercial or institutional. 

The U.S. also has about 3.7 GW of geothermal electric generating capacity, more than 90% of which is in California and Nevada. That represents less than 1% of U.S. capacity, but IEA says it could grow to more than 8% by 2050. Geothermal’s potential for direct use is 231 GW by 2050, including up to 17,500 district heating and cooling systems, according to the agency. 

Geothermal heating and cooling system representation | NYSERDA

The 2022 Utility Thermal Energy Network and Jobs Act required the New York Public Service Commission to create regulatory frameworks for thermal energy networks and utilities to pilot at least one district or community-scale geothermal infrastructure project (S9422). The PSC issued guidance on this law in a September order, requiring utilities to submit their proposals by the end of this year. If approved, the projects will move on to engineering design and construction, with a target of being operational by 2025 (22-M-0429). 

To encourage growth of the technology, New York offers a Geothermal Income Tax Credit that covers 25% of expenditures up to $5,000 for homeowners. The New York State Energy Research and Development Authority’s (NYSERDA) Clean Heat initiative offers rebates to incentivize the switch from fossil fuel-based systems (18-M-0084). Additionally, the state promotes the use of federal tax credits under the Inflation Reduction Act, which can cut installation costs by 30% through 2032, plus a 10% domestic content bonus, though these decrease in 2033 and 2034. 

New York City offers an online feasibility tool to identify areas where ground source systems could be used to retrofit buildings’ heating and cooling systems. HeatSmart CNY offers assistance to building owners considering geothermal in Central New York. 

Harckham said his goals for geothermal energy during the next legislative session is to “make it more accessible” by increasing state incentives. 

Reactions

Reactions to S6604 have been overwhelmingly positive.  

Sen. Mario Mattera (R), the ranking member of the Environmental Conservation Committee, praised Harckham for proposing S6604, saying, “This is a great bill. Me, being in the plumbing business, this is very, very important for renewable energy and for our future.” 

In an interview with NetZero Insider, John Ciovacco, a board member at NY-GEO and president of Aztech Geothermal, said that New York’s actions will “simplify the conversion of buildings to these systems.” 

“Having agencies like the [Department of Environmental Conservation] at the table opens us up to try and develop appropriate regulations and formulate ways to address everyone’s concerns,” Ciovacco said. 

Pat McClellan, policy director at the New York League of Conservation Voters, described S6604 as “just another brick in the wall” to expand geothermal energy in the state, calling it a “common sense measure.” 

McClellan emphasized that while New York has made significant strides in geothermal action, challenges like public awareness and long-term planning remain. State agencies and utilities “did an excellent job laying out ‘here’s where we are and here’s how we get there,’” he said, but there still is not enough attention paid to the 10-, 15- or 20-year time frames, “which is the time horizon we need to start think about in order to avoid future price shocks.” 

Dandelion’s Deese said the state should consider raising its geothermal income tax credit to encourage consumer adoption. “More definitely needs to be done to raise awareness of geothermal,” she said, because many people have “not heard of geothermal heating and cooling before seeing a Dandelion advertisement.” 

In response to questions from NetZero Insider, the DEC said it is assessing the best ways to communicate with stakeholders impacted by the new regulations, including by updating public websites and advising about best practices around these systems. 

Michal Charles Moore, a visiting professor of economics and systems engineering at Cornell University, emphasized the importance of legislative recognition for geothermal energy. Cornell researchers last year drilled a 2-mile-deep exploratory Earth Source Heat borehole to demonstrate geothermal’s capabilities. 

Moore said bills like S6604 are a “nod from the government” that stimulates additional research funding, collaboration and public trust. 

“The industry just got a big boost,” Moore added. “They got acknowledged but are now on the hook to deliver.” 

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Exelon Q3 Earnings Call Links Transmission Expansion to Rate Cases

Exelon utilities have scored some big wins in the past few weeks, beginning with PJM’s selection on Oct. 31 of project proposals for a competitive transmission solicitation, including an $850 million package of projects for the utility and its subsidiaries, CEO Calvin Butler announced during a Nov. 2 third-quarter earnings call.

The package includes projects for Baltimore Gas and Electric (BGE), PECO, Pepco and Delmarva Power & Light, with completion dates scheduled for 2029 and 2030, timeframes that “extend beyond the current guidance range,” Butler said. “It provides another good indication of the trends in place and degree of work that the grid will require, well into the future.”

Other forward-looking developments include Exelon’s active role in two of the seven regional hydrogen hubs the Department of Energy announced Oct. 13, Butler said. Commonwealth Edison (ComEd) is part of the team working on the Midwest hub, while PECO and Pepco will be similarly involved in the mid-Atlantic hub. (See DOE Designates Seven Regional Hydrogen Hubs.)

ComEd and PECO also were named to receive $50 million and $100 million, respectively, as part of DOE’s $3.46 billion Grid Resilience and Improvement Program, announced Oct. 18. A total of 58 projects received grants from the program, which is funded by the Infrastructure Investment and Jobs Act. (See DOE Announced $3.46B for Grid Resilience, Improvement Projects.)

ComEd will use the money to deploy “next-generation technologies” that will support wider adoption of electric vehicles and solar, while PECO’s grant will go to grid hardening in “vulnerable areas” of the utility’s service territory to help keep the power on during extreme weather events.

“The federal support is critical to supporting an affordable and equitable transition,” Butler said. “The need for transmission expansion, the investment in new energy supply and the ever-increasing need for more resilient grids all highlight the impact that an economy that is increasingly dependent on electricity will have on our investment plan.

“The energy transformation will last decades, not years, which is why we are confident that investment opportunities will continue to strengthen and lengthen our rate base growth.”

The PJM selection is a case in point. The grid operator opened the window for the solicitation to expand transmission to meet new demand being created by the rapid expansion of data centers in Northern Virginia, as well as the impact of the pending retirements of fossil fuel generation, such as Maryland’s Brandon Shores coal-fired plant.

While Butler did not provide details on the Exelon projects, PJM said it is recommending a mix of new substations and transmission as well as upgrades to existing facilities. The recommendations will go back to PJM’s Transmission Expansion Advisory Committee before being sent to the Board of Managers for final approval.

Looking at local grid improvements, Chief Financial Officer Jeanne Jones highlighted a recently completed grid upgrade on Maryland’s Eastern Shore, the 11-mile East New Market to Cambridge project, which installed new state-of-the-art steel poles to bolster local reliability. The new poles can withstand 120-mph hurricane force winds, she said.

Tackling Multiyear Rate Plans

The connection between transmission buildout, the energy transition and Exelon’s rate base was a central theme throughout the call, as Butler and Jones gave a rundown of the six rate cases the company’s utilities have before regulators in Illinois, New Jersey, Maryland, Delaware and the District of Columbia.

In ComEd’s rate case, a recent proposed order from an Illinois administrative law judge (ALJ) recognized “that meeting the ambitious electrification and decarbonization goals set by [the state’s] groundbreaking Climate and Equitable Jobs Act will require ComEd to make significant investments,” Butler said.

But the ALJ set a return on equity below the national average, he said. “It does not allow for prudent capitalization of the business.”

According to Butler, a recommendation from staff at the Illinois Commerce Commission (ICC) set an 8.9% rate of return, which the ALJ upped to 9.28%. ComEd’s proposal calls for a 10.5% rate of return in 2024, rising incrementally to 10.65% in 2027, according to a report in Crain’s Chicago Business.

A final order is expected in December, and ComEd will continue to make its case before the ICC, Butler said. Jones noted that the ComEd filing is its first run at a multiyear rate plan and framed the ALJ’s proposed order as “just another data point in the process,” given the number of variables at play in multiyear plans.

Four of the six rate cases — for BGE, Pepco Maryland, Pepco DC and ComEd — are for first-time multiyear plans, she said.

The Numbers

Butler noted that despite a mild winter and late summer storms with 110-mph wind gusts that knocked out power to 1.3 million Exelon customers, the utility’s earnings were still on track with its 2023 predictions.

The utility’s third quarter GAAP net income was $700 million ($0.70/share), while non-GAAP adjusted net income was $671 million ($0.67/share).

Butler said the utility is narrowing its guidance for 2023 as a whole to $2.32 to $2.40/share.

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FERC Approves Reliability Standard Retirements, Replacements

FERC has approved two new reliability standards developed through NERC’s Standards Efficiency Review (SER) process while agreeing to the retirement of six others. 

The two new standards, TOP-003-6.1 (Transmission operator and balancing authority data and information specification and collection) and IRO-010-5 (Reliability coordinator data and information specification and collection), were adopted by NERC’s Board of Trustees at its meeting in August. (See “Standards Process Changes Accepted,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.) FERC gave its approval in a filing Thursday, noting that no motions to intervene, comments or protests had occurred during the 30-day comment period (RD23-6). 

Phase 2 of the SER produced four efficiency concepts for NERC to pursue in future standards development activities; the second of these concepts concerns consolidation of information and data-exchange requirements, which the new standards are intended to address. This recommendation was based on the concern that requirements in the current reliability standards might create “unnecessary administrative burdens” for entities trying to demonstrate compliance, as the ERO said when submitting the standards to the commission. 

The goal of Project 2021-06, which developed IRO-010-5 and TOP-003-6.1, was to simplify the burdens associated with the standards they will replace while limiting data retention requirements that are not necessary to grid reliability and clarifying expectations regarding data specifications. The changes to the final standards mainly apply to the data retention requirements, which NERC said in its submission are “substantively similar, if not functionally identical” between the two standards. 

IRO-010-5 contains new language requiring reliability coordinators to maintain specifications for “the data and information necessary … to perform [their] operational planning analyses, real-time monitoring and real-time assessments.” It replaces language requiring “a periodicity for providing data” with more detailed requirements detailing time periods and criteria for respondents to provide data, and for identifying a process to resolve conflicts with respondents. 

TOP-003-6.1 received similar changes, in keeping with NERC’s proposal to bring the two standards closer in line with each other. The main difference between the two is that TOP-003-6.1 targets transmission operators and includes language relating to their relationships with their balancing authorities. 

The commission also approved the implementation plan submitted by NERC, according to which both standards will become effective on the first day of the first calendar quarter 18 months after FERC approval. According to that timeline, the standards will take effect July 1, 2025. 

NAESB Rules to Replace MOD A Standards

FERC also agreed Oct. 26 to the retirement in their entirety of six standards identified in the SER as “no longer necessary” (RM19-17): 

    • MOD-001-1a (Available transmission system capability); 
    • MOD-004-1 (Capacity benefit margin); 
    • MOD-008-1 (Transmission reliability margin calculation methodology); 
    • MOD-028-2 (Area interchange methodology); 
    • MOD-029-2a (Rated system path methodology); and 
    • MOD-030-3 (Flowgate methodology). 

NERC submitted the proposed retirements to the commission in 2020 while also proposing to retire four other standards and modify five more; the latter retirements were accepted at the time. (See FERC Accepts Removal of 18 NERC Requirements.) 

However, while FERC gave its preliminary approval to retire the so-called MOD A standards, the decision was complicated by the fact that the commission’s intended replacement for these standards — the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities — had recently been updated. At the time, FERC was still accepting industry comments on its proposal to adopt the updated NAESB standards. 

The commission decided to defer its decision on the MOD A standards until “a later time.” In its filing last month, FERC noted that the NAESB standards have been fully implemented and that it was now satisfied that removing the MOD A standards “will not result in a reliability gap.” 

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Duke Earnings Slip on Low Demand, but Long-term Growth Expected

Duke Energy saw its third-quarter earnings drop from a year ago as it dealt with mild weather and low demand from industrial customers, but executives told analysts Thursday those trends should turn around.

Earnings per share fell to $1.59 on the quarter, compared to $1.81 in the summer of 2022. On top of a return to growing demand, Duke CEO Lynn Good also highlighted plans to transition its utilities around the country to cleaner resources.

“With the closing of the commercial renewable sale last month, our portfolio repositioning is completed,” Good said. “We are now a fully regulated company, operating in some of the fastest-growing and most attractive jurisdictions across the U.S.” (See Duke Sells Distributed Renewable Business to Arclight.)

The firm’s biggest market is the Carolinas, where it dominates the utility space. The North Carolina Utilities Commission (NCUC) recently approved new rates for Duke Energy Progress and has a pending case before it for Duke Energy Carolinas (DEC) that Good said should wrap up in the fourth quarter.

The NCUC approved a rate base of $12.2 billion and $3.5 billion in investments for the firm, while a settlement pending in DEC’s case would set its rate base at $19.5 billion and approve $4.6 billion in funding. While the firm has several subsidiaries serving the Carolinas, it plans their system jointly, and it filed the latest iteration of its resource plan with the two states in August.

“The single unified resource plan for the Carolinas is designed to meet the needs of this growing region spurred by rapid population growth and significant economic development activity,” Good said. “The plan maintains an all-of-the-above strategy with a diverse deployment of additional resources, including renewables, battery storage and natural gas, as well as energy efficiency and demand-side management.”

Sales volumes are down 1.2% on a rolling 12-month basis, with industrial customers saying they are scaling back their business slightly because of uncertainty in the economy, said CFO Brian Savoy.

“Most are describing the pullback as temporary, and there’s optimism that it’s about to turn around in mid- to late 2024 and into 2025,” Savoy said. “We continue to see strong customer growth from population migration and robust economic development, giving us confidence in growth over the long term.”

Textiles and the paper industry have been hit by slowdowns, but other industries are facing issues with the supply chain, labor and interest rates that have contributed to lower demand, Good said. Others have built up a significant inventory of product and have cut back on production to sell off the excess.

Residential demand had been impacted by the trend of returning to work after the pandemic, but that is over, Good said. Lingering residential demand weakness will be offset as Duke moves to decoupled rates in North Carolina next year, Savoy said.

“We’ve got customers sort of working through the macro-term trends here in the short term,” Good said. “But over the long term, we continue to see this economic development being incredibly strong.”

Economic development projects coming online next year add up to 1,000 to 2,000 GWh of new demand, with Duke expecting to add 7,000 to 9,000 GWh by 2027, a growth rate of between 0.5 and 1%, Savoy added. That load growth is reflected in Duke’s plans to expand its generation in the Carolinas.

“We see a need for additional megawatts in the Carolinas really driven in large measure by population growth, economic development and reserve margin,” Good said.

Populations are also growing in the other states in Duke’s footprint. The utility is planning to start transitioning its Indiana utility away from coal-fired generation to rely more on natural gas and renewables, Good said. Duke expects to file certificates to build new generation in the Hoosier State in the next several months.

The plan in North Carolina also calls for new natural gas. One analyst asked Good about potential pushback against new fossil infrastructure.

“We believe what we’ve put forward is a very balanced, all-of-the-above strategy that provides the right balance between reliability, affordability and increasingly clean, which is our commitment to the state,” Good said. “So, we think all of those elements will be closely reviewed and evaluated as part of the process in front of the commission.”

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Wash. Looks to Join California-Quebec Cap-and-Trade Market

Washington state will tentatively seek to link its cap-and-trade program with the California-Quebec carbon market in an effort to reduce the financial impact of pricing carbon across its economy. 

Laura Watson, director of Washington’s Department of Ecology, announced the decision Nov. 2, two weeks after the agency released a preliminary study showing the state would benefit from linking with the older and larger carbon allowance market. (See Analysis Favors Wash. Linkage with Calif. Cap-and-trade Program.) 

Watson said the state’s final decision will depend on the outcome of talks with the California-Quebec coalition. The earliest the two markets could be linked is 2025. 

When Washington’s legislature passed the state’s cap-and-invest law in 2021, it directed the state government to investigate linking with other cap-and-trade markets in an effort to reduce costs for buying allowances. Clearing prices for Washington’s allowances have been linked to increased gasoline prices in the state this year, the first for the cap-and-trade system.   

While Washington and the California-Quebec coalition have informally discussed how to align their respective cap-and-trade programs, no formal talks have begun, Watson said. 

The nuts and bolts of meshing the two systems will have to be addressed before linkage. For example, Washington limits a bidder to buying 10% of the available allowances per quarter, while the California-Quebec market allows for 25%. Washington would likely have to agree to the 25% limit, Watson said. Luke Martland, implementation manager for Washington’s cap-and-invest program, said adopting the higher limit is unlikely to lead to any entities cornering the allowance market. 

The public will have input on a draft agreement, if one is reached.  

“California is also required to undergo its own evaluation and public process for any changes that would be required to pursue linkage. We believe subnational collaboration such as program linkages is an important tool to address a global issue such as climate change,” Lys Mendez, spokesperson for the California Air Resources Board, told NetZero Insider.   

The Ecology Department’s preliminary analysis concluded the proposed linkage likely would improve the Washington cap-and-invest program’s economic durability, longevity and efficacy.  

“In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization,” the report said. 

Participants in Washington’s cap-and-invest program would be able to more effectively perform long-range planning and pursue expensive investments in anti-carbon measures more readily, the report said.  

Washington’s carbon allowance market now is slightly bigger than Quebec’s alone, but only 18% the size of the combined California-Quebec program. 

The preliminary analysis estimated Washington’s market by 2025 would be just 16% the size of the California-Quebec system. 

Joel Creswell, Ecology’s climate policy section manager, recently briefed the state House Environment and Energy Committee about the proposed move. He said a three-government cap-and-trade coalition likely would shrink Washington’s final bid prices in its quarterly cap-and-invest auctions.  

But a state Republican leader was critical of Ecology’s decision to move closer to linkage. 

“California has the highest gas prices in the country and the third highest retail electricity rates in the country. … Everything California policymakers touch related to energy markets ends in disaster for consumers,” state Rep. Mary Dye, ranking Republican on the House Environment and Energy Committee, said in a press release.   

Critics of Washington’s cap-and-invest system have blamed the program for the state’s high gasoline prices. However, program supporters put the cause on oil companies’ exploiting the program to charge more at the pump. Washington’s Democratic legislators plan to introduce an oil industry financial transparency bill in the 2024 session.  

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ACP: Solar, Storage Soar in Record-breaking Q3; Wind Sputters

The U.S. grid added a record 5,551 MW of utility-scale solar, wind and storage in the third quarter of 2023, according to a new report released Wednesday from the American Clean Power (ACP) Association.

But while the overall numbers in ACP’s Clean Power Market Report were strong — a 13% year-over-year increase in clean power capacity — the results for individual sectors were uneven. Utility-scale solar coming online jumped 31%, but new wind capacity fell 77%. Only two onshore projects totaling 288 MW came online, the lowest figures the industry has seen since 2013, according to the report.

While solar and storage saw strong year-over-year growth in Q3, wind took a 77% nosedive. | ACP

Commercial and industrial (C&I) power purchase agreements (PPAs) were down 55% year over year, as buyers announced 3,175 MW of new contracts. According to the report, the drop reflects an ongoing slowdown in C&I PPAs.

At the same time, project delays continue to hamper industry growth. Developers put close to 23 GW of new capacity on hold last quarter because of delays, adding to other projects still unfinished from 2021 and 2022. Delayed capacity now stands at more than 56 GW, the report says.

While acknowledging such “near-term challenges,” ACP CEO Jason Grumet remains bullish on the U.S. clean energy market. The country currently has 243.4 GW of clean power capacity online, with a pipeline of 1,220 solar, wind and storage projects totaling an additional 128.2 GW, according to the report.

“The demand for clean energy is undeniable,” Grumet said, adding that the quarter’s “record-breaking numbers tell us that the U.S. clean energy sector continues to grow on a healthy, long-term trajectory.”

Other topline findings from the report include:

    • The wind sector could bounce back from its disappointing quarter, with projects totaling 12,856 MW now under construction, including 803 MW that broke ground over the three months from July to September. Including projects under construction and in development, the total pipeline is now 22,135 MW.
    • California took the No. 1 spot for new clean energy installations in Q3, with 1,900 MW of solar and storage added to the grid, but Texas still leads the nation in cumulative clean energy online — 56,948 MW — with No. 2 California trailing well behind, with 31,726 MW.
    • Hybrid projects, mostly combining solar and storage, continue to grow, with 2,908 MW coming online, up 30% over the same period last year. At present, the U.S. has 18,447 MW of hybrid projects in operation, 80% of which are solar and storage.

Waiting on the IRA

What’s behind all those numbers is the ongoing push-pull of the federal incentives from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, and market forces from inflation to supply chain pressures and workforce shortages.

Like ACP, the Solar Energy Industries Association (SEIA) and Wood Mackenzie’s Solar Market Insight Report for the second quarter, released in September, noted that “the full benefits of the IRA have yet to materialize.”

But, for a change, the main problem is not project financing. “If anything, the amount of capital seeking high-quality solar project investments has only increased,” the SEIA-WoodMac report said. On top of inflationary pressures in the form of high interest rates and rising equipment and labor costs, developers are still uncertain about whether their projects will be able to qualify for IRA tax credits.

Despite guidelines issued by the Treasury Department, questions still linger. “As a result, the full benefits of the IRA, in the form of more development of solar projects that meet various policy objectives, won’t manifest until developers, asset owners and financiers have enough regulatory clarity to make confident investments,” the report says.

Many projects originally put on hold in 2021 and 2022 have yet to come online, along with 23 GW year-to-date this year. Solar accounts for two-thirds of delayed projects. | ACP

Looking at project delays, the ACP report says that on average, project delays run about 14 months, but 39% of delayed projects have experienced multiple setbacks — in some cases, five. Solar projects make up 67% of the delayed projects.

Still another caveat is that both the ACP and SEIA reports look at clean energy capacity, not generation, and few clean energy projects produce power at their full megawatt capacity. While renewables continue to outpace fossil fuels in new power added to the grid and waiting in interconnection queues, according to the Department of Energy, wind and solar combined now generate about 12% of U.S. electricity.

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EPRI: Changing Loads Raise Concerns for Modelers

The changing nature of large loads on the power grid is already making system modeling more challenging, and the problem will only grow as the shift continues, according to presenters at a webinar hosted by NERC, the North American Transmission Forum and the Electric Power Research Institute. 

Speaking at the first day of the annual Planning and Modeling Virtual Seminar on Wednesday, Parag Mitra, a senior technical leader at EPRI, said that while “we have been used to modeling large electric loads on our system for many years,” the kind of applications that make up those large loads has undergone a major shift in recent years. 

Whereas traditionally large loads comprised factories, steel mills and other large industrial functions, their newer counterparts are mostly electronic in nature — for example, cryptocurrency mining operations, data centers, hydrogen electrolyzers and electric vehicle chargers. Mitra explained that modelers are still coming to terms with the fact that although these new applications are comparable to their industrial forebears in the size of demand, their performance on the grid can be very different. 

“If you looked at a steel mill, you had a whole bunch of different motors that were running, and there were a bunch of different processes; whereas if you think of a data center, a large electrolyzer or a crypto-mining facility, all of these are large loads, but 90% of that [demand] is just a single type of process,” albeit spread across multiple machines, Mitra said. “The problem with that is, if one of those [electronic] devices behaves in a certain way, which may or may not be grid-friendly, you can anticipate that the entire facility is going to behave in that way.” 

The concept of grid-friendly and grid-unfriendly behavior, as NERC Senior Engineer John Skeath explained later in the seminar, has previously been expressed primarily in relation to EV chargers. (See NERC, WECC Outline EV Charging Reliability Impacts.) Grid-friendly behavior contributes to the overall stability of the power grid by, for example, reducing power draw when system voltage drops; by contrast, grid-unfriendly applications aim to maintain a constant power level regardless of system voltage, which can hurt grid stability by raising current draw when voltage is low. 

Mitra said that the large industrial loads of previous years were grid-friendly by nature; during a system disturbance, they would either trip offline or reduce their power draw without requiring any specific action. Electronic loads are different because the devices that make them up require a constant power draw, so their demand will not drop during a disturbance unless this behavior is programmed in. 

Some facilities may also have backups like a local generator or uninterruptible power supply, which makes predicting their behavior during a disturbance even more difficult; if a facility switches to a backup generation source, when will its demand return to the grid? 

“These devices may not trip offline; they might just move onto a local generation source or a local battery, but then they just disappear from the grid. So that can be a big issue if these loads are significantly sized,” Mitra said. 

The challenge is compounded in systems with high levels of inverter-based resources (IBRs), including wind and solar generators, which present challenges of their own to system modelers, Mitra said. (See IBR Models Remain Persistent Challenge, Task Force Warns.) Because both the shift to IBRs and the growth in electronic loads are likely to continue, grids designed in the future without a better understanding of both sides of the equation will face greater risks to reliability. 

Mitra said that building an understanding of these resources requires deep communication with manufacturers of the electronic equipment, who “have, for the most part, not been involved in this conversation.” Making these companies part of the discussion can help educate them about the burdens they place on the system, but also inform the modelers when their expectations are unrealistic. 

“There will be places where … you want to ask loads to follow a certain type of ride-through requirement,” Mitra said. “It’s going to be important to understand what the limitations of the loads are. [If you ask] a load to do a certain thing, it’s not a generator; it might not be able to provide those benefits, simply because it was never designed to provide grid support; it was probably designed to serve another purpose. So [it’s] important to have the discussion … so that we know what type of solutions are required to solve all these issues.” 

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FERC Approves CAISO Wheel-through Rule Changes

FERC on Oct. 30 approved a raft of CAISO tariff changes intended to ease temporary restrictions on wheeling power through the ISO’s grid under emergency conditions.

The approval came despite numerous protests from Western entities that considered the revised wheel-through rules to still be overly biased in favor of CAISO’s native load (ER23-2510).

CAISO implemented interim wheel-through restrictions in 2021 as part of a package of changes meant to promote summer reliability following the rolling blackouts and energy emergencies of summer 2020.

The rules reprioritized wheel-throughs so energy transfers between balancing authority areas in the Northwest and Southwest could no longer take precedence over capacity needed to serve CAISO native load. Under the rules, non-CAISO entities were required to apply at least 45 days in advance to designate high-priority wheel-throughs needed for reliability, giving the wheels equal standing with CAISO native load.

Until that time, CAISO — unlike other RTOs/ISOs — had never established mechanisms within its tariff to set aside transmission capacity to serve native load, notably not including native load requirements in its transmission commitments when calculating available transmission capacity (ATC).

Additionally, CAISO never adopted a transmission reservation system to protect its ability to serve native load when the ISO is constrained.

“Instead, when there was insufficient transmission capacity to support all intertie transactions, CAISO’s market software determined the priority order in which self-schedules would be curtailed using real-time market parameters known as penalty prices that were set forth in a business practice manual,” FERC noted in its Oct. 30 order.

In March 2022, FERC upheld its 2021 approval of CAISO’s wheeling restrictions, rejecting a rehearing request by the Arizona Corporation Commission and a coalition of Arizona utilities, including Arizona Public Service and Salt River Project, which argued CAISO’s rules discriminated in favor of the ISO’s load (ER21-1790).

But the commission at the time also pointed to continued divisions over the rules in the region and directed CAISO to “work with stakeholders to design and file a just and reasonable and not unduly discretionary or preferential long-term solution as expeditiously as possible.”

Changing Formulas

The CAISO tariff changes approved Oct. 30 are intended to give wheel-through transactions at the ISO’s interties the same scheduling priority as that of imports serving the ISO’s load. At the same time, the changes also elevate the scheduling priority of serving native load by altering CAISO’s ATC calculation to set aside intertie capacity for that load.

Under the new rules, CAISO will estimate ATC at the interties “monthly across a rolling 13-month horizon and daily across a seven-day horizon to derive the amount of transmission capacity available for entities seeking a monthly or daily Wheeling Through Priority,” the commission said in its order.

In its calculation for estimating the ATC for wheel-throughs at an intertie, CAISO will subtract both existing transmission commitments (ETComm) and the transmission reliability margin (TRM) from the total transfer capability (TTC) on the line. Under a new formula, the definition of ETComm is revised to include transmission ownership rights (TOR) and existing transmission contracts (ETC) — as it currently does — as well as transmission capacity for wheeling through priorities and native load needs, including native load growth in the applicable time horizon.

“CAISO states that it will initially determine the amount of transmission capacity to serve native load needs at each intertie for each calendar month based on the highest MW quantity of total RA and non-RA import supply under contract dedicated to serving CAISO load serving entities’ load as demonstrated by RA showings, and showings of historical contract information regarding non-RA import supply, at the intertie for that same calendar month during the previous two years,” FERC notes.

Powerex, NV Energy, the Arizona utilities and the Electric Power Supply Association (EPSA) argued CAISO’s proposal for calculating ATC would be “unduly preferential” to native load and would result in the ISO setting aside more intertie capacity than necessary to reliably serve its load.

Powerex contended CAISO’s own data indicates the availability of intertie capacity for priority wheel-throughs would be much lower under the new rules than under the current interim measures. NV Energy complained about a lack of clarity in how CAISO will calculate ATC values.

The Western Power Trading Forum (WPTF) and EPSA argued the proposed ATC calculation would set aside intertie capacity for native load without requiring CAISO load-serving entities to show they have contracted firm resources in a timely manner, whereas external LSEs could secure wheeling only through priority if they meet a power supply contract requirement.

The commission brushed aside those concerns, and others, in approving CAISO’s ATC calculation.

“As a threshold matter, we find no merit in any suggestion by protestors that CAISO is not entitled to set aside intertie capacity that is needed to serve CAISO load, or that it is unduly discriminatory in principle for CAISO to reserve this capacity for native load before making ATC available to external load serving entities,” the commission wrote.

The commission added that “one of the core elements” of FERC’s open access policies “is the ability of transmission providers to include in their tariffs certain protections to ensure reliable service to native and network load customers. [FERC] Order No. 888 establishes that public utilities may reserve existing transmission capacity for native load and reasonably foreseeable network transmission customer load growth.”

‘Inherent Tension’

FERC also approved CAISO’s proposed process for requesting and using priority wheel-throughs. For the monthly request window, the process will require a scheduling coordinator to request a wheeling-through priority no earlier than 12 months before the month for which it seeks the priority and not later than one month before the effective date of the priority. Daily wheeling-through priorities can be requested no sooner than seven days before and no later than one day before the priority effective date.

Protestors once again contested the provision that a wheel-though request must be supported by an executed firm power supply contract. CAISO said the contract requirement was an extension of its interim wheel-through tariff provisions and consistent with the requirement for external LSEs seeking to obtain an allocation of congestion revenue rights in the ISO. The grid operator said the contract requirement helps ensure that limited ATC on the interties is accessible to those that show they need it to serve their load and comparable to how RA contracts demonstrate the same need for CAISO LSEs.

The commission said that when it accepted CAISO’s interim scheduling priority rules in 2021, it explained that the firm contract requirement was not preferential for CAISO because it functions as “reasonable proxy that allows external load serving entities to demonstrate that they plan to use the CAISO grid to serve load in a manner that is comparable to CAISO load serving entities.”

“We find that the commission’s reasoning in that case applies with equal force here because the central issue is still the inherent tension between CAISO’s need to use intertie capacity to serve its own load and third parties’ ability to access that capacity,” the commission wrote.