Page 77 – RTO Insider

June 25, 2024June 26, 2024

LNG Won’t Replace Coal in Generating China’s Power, Report Says

While natural gas has taken a huge bite out of coal’s share of the electric generation market in the U.S., LNG will not have the same impact globally, according to a new report from the Institute for Energy Economics and Financial Analysis (IEEFA).

That is because China, the world’s largest coal consumer, will not be replacing that domestic resource with imported natural gas, IEEFA said in its report, “LNG is not displacing coal in China’s power mix.”

“Policymakers in both LNG exporting and importing countries should approach claims about the necessity of LNG as a ‘bridge fuel’ with a high degree of skepticism,” report co-author Sam Reynolds said in a statement. “The case of China clearly shows that LNG has played a minimal role in displacing coal in the country’s largest coal-consuming sectors.”

China is the world’s largest energy consumer, with coal accounting for 55% of its primary energy demand, while natural gas, hydropower and renewables each provided 8% of primary energy consumption in 2022.

Over the past decade, natural gas’ share of generation has stayed around 3%, while renewables have grown to 16% and contributed more to coal’s falling share of generation from 70% to 61%.

“Although China is the world’s largest LNG importer, the country’s coal demand has increased more than LNG imports every year since 2017,” the report said. “Claims about the role of LNG in displacing coal usage appear to be based on hypothetical arguments that coal generation would be even higher without gas-fired power.”

While coal’s share of total generation has fallen over the last decade, its generation output has grown by 1,700 TWh, which suggests coal is not being displaced in absolute terms, while wind and solar have contributed to its decline in share of overall generation.

Recently, China even passed policies to “strictly control” coal-to-gas switching and promote domestic production of coal and natural gas.

“As a result, coal capacity additions have far outpaced additions of gas-fired power plants, and both are dwarfed by wind and solar installations,” the report said. “National energy sector development plans have called for coal plants to provide flexible operations to integrate variable renewables sources.”

LNG also costs three times as much as coal in China, so even if prices for imported gas drop as new supply comes online in the near future, those declines likely will not be enough to close the gap. China has replaced coal heating with gas heaters in urban areas, but the paper suggested that would be hard to replicate in the countryside.

China is the fourth-largest producer of natural gas, which has been growing in recent years, but it is the largest coal producer, last year hitting record production of 4.7 billion tons, 14% above 2021 levels.

China is also the largest importer of coal, with imports accounting for about 10% of supply needs.

“The country’s coal, natural gas and LNG demand have all increased since 2016,” the report said. “China consumes nearly seven times more coal than natural gas, though consumption of both fuels increased by roughly the same amount (8 exajoules) between 2012 and 2022.”

Electricity generation has grown 6.3% a year since 2013, with coal, natural gas, wind, solar and nuclear increasing every year over that time frame.

“Looking ahead, generation from coal and renewables will continue to exceed gas-fired generation, and capacity investments suggest that LNG and gas will continue to play a limited role in coal displacement,” the paper said. “In recent years, gas plant capacity additions have paled in comparison to coal and renewables additions.”

China had 1,051 GW of installed wind and solar at the end of 2023 and could hit 1,300 GW this year, beating its target of installing 1,200 GW of wind and solar by 2030. That trend has the International Energy Agency predicting the country could get 50% of its generation from renewables by 2028, while IEA’s projections for gas power are flat through 2030.

June 25, 2024June 26, 2024

DOE Dives into US Offshore Wind’s Growing Pains

U.S. Department of Energy officials say they’re optimistic the costs of offshore wind energy development will begin to ease by the end of the decade.

They struck an optimistic tone during a June 25 webinar, acknowledging the growing pains the industry has had as it establishes itself in the United States but saying the problems of the past 20 months can be overcome.

Jigar Shah, director of the DOE Loan Programs Office, said while the complicating factors were not unique to U.S. offshore wind development, U.S. offshore wind was particularly vulnerable to them.

“With all that said, global cost headwinds have begun to stabilize and new offtake solicitations from states are de-risking development moving forward,” Shah said. “Government and industry are drawing on lessons learned with ongoing efforts to refine project and supplier procurement, foster regional collaboration for supply chain and transmission planning and make investments to support necessary enabling infrastructure.”

Jocelyn Brown-Saracino, DOE’s offshore wind lead, said wind energy area leases held by developers total more than 50 GW of potential generation capacity. Offshore wind is a headline priority for the Biden administration, which plans to auction more leases this year.

“That said, the last year was a tumultuous one for offshore wind. The industry was hit by a perfect storm of global macroeconomic challenges,” she said. “The sector is adapting, however, and improved risk mitigation is being built into industry planning.”

The webinar was centered on the DOE’s “Pathways to Commercial Liftoff” report for offshore wind, released in April during the 2024 International Partnering Forum. (See Interior Announces Updated OSW Regs, Auction Schedule at IPF24.)

Lead authors Brett Anders and Jonah Uri summarized three key takeaways from that report:

- Offshore wind will play a critical role in coastal decarbonization and would be hard to replace with other sources of emissions-free power.
- Roughly 6 GW of projects are under construction but there needs to be 10 GW to 15 GW this decade to ensure development of a domestic supply chain and reduce some of the long-term risks of building supporting infrastructure.
- State policy drives the offshore wind market more than it drives other technologies; federal policy mechanisms such as the Inflation Reduction Act offer support but have not been enough on their own to overcome the challenges created by macroeconomic conditions.

Globally, offshore wind is a mature technology that has grown tenfold in the past decade and is projected to grow fivefold in the next decade, they said.

The United States is late to the table, however, home to less than 0.5% of the world’s operational capacity and struggling to add more.

More than half of the projects contracted off the Northeast coast have been canceled or have canceled their offtake contracts in the past year, victims of soaring costs and supply chain or infrastructure constraints that made it impractical to proceed to construction under the financial terms negotiated.

The projects being contracted now are much more expensive. The levelized cost of electricity (LCOE) has risen from $85/MWh for fixed-bottom offshore wind projects that reached final investment decision (FID) in 2021 to a projected $140/MWh for projects reaching FID in 2023-2026.

That is mainly due to the rising cost of capital, cost of construction and cost of operation. Offshore wind is highly sensitive to the cost of capital, said Anders, a member of the market analysis team at the DOE’s Office of Technology Transitions. A 2% increase in the cost of debt alone would lead to a roughly 20% increase in LCOE.

The report estimates that FIDs reached in 2030 will be back down to $84/MWh through a combination of decreasing interest rates, commodity prices and inflation, and because of tax credits and policy support.

“Given the inherent uncertainties in the market, particularly with respect to macroeconomic challenges, these estimates should not be interpreted as a cost forecast but rather a framework for understanding the cost of offshore wind today and into the future,” said Uri, a transaction specialist at the Loan Programs Office.

The economics seen in the era after the Great Recession and before COVID or the war in Ukraine offer some basis for optimism, the report notes: As worldwide installed offshore wind capacity surged from 3 GW in 2011 to 33 GW in 2021, the LCOE of new wind farms gradually decreased 60% through factors including supply chain efficiencies, de-risked construction, technology innovations, institutional knowledge and turbine upsizing.

Some of the complicating factors in the United States today, such as lack of domestic manufacturing capacity, ports and specialized installation vessels, are particularly sticky, Uri said: They must be put in place at a cost of hundreds of millions of dollars each before the projects that will pay for them can be built.

“So, the early movers are a primary engine to fund the long-term ecosystem buildout for offshore wind here in the U.S., whether that’s ports, vessels, supply chain, etc.,” he said. “It’s a key area of risk that we focus on and part of the reason why building out the initial wave of projects and getting over this hump, of this chicken and egg, is a key force to help lock in the future of the industry.”

The tone of the webinar and the report on which it is based is optimism in the face of setbacks.

A central feature of the DOE “Liftoff” series of reports on new energy technologies is the projection of the liftoff — the point at which an industry sector begins actively contributing to decarbonization goals and has a sustained pipeline of projects regularly reaching completion.

“We found that offshore wind liftoff can be achieved in less than 10 years driven by deployment of projects in the 2020s, several of which are under construction today,” Anders said. “Liftoff for offshore wind will require steady deployment enabled by continued refinements to project sequencing and funding.”

June 25, 2024June 26, 2024

NJ Senate Energy Committee Backs PJM Interconnection ‘Skip’ for Solar

New Jersey’s Senate Environment and Energy Committee on June 20 passed a bill (S3308) supporters said would allow grid-scale solar projects of up to 20 MW to bypass PJM’s interconnection queue and connect to the grid through their local utility.

The committee voted 5-0 to advance the bill, which would require electric utilities to “accept, process and approve” solar projects of 2 MW to 20 MW to the transmission and distribution system, unless the application is incomplete or the utility believes the interconnection would be “unsafe or a risk to the stability of the utility’s electric distribution or transmission system.” In those cases, the utility would have to provide the developer with recommendations on how to modify the proposal to make it complete or “reconfigure, downsize or otherwise modify” it to remove the risk.

The bill would require the utility to “timely process any complete interconnection applications received.” The owner or developer of an approved project would be required to pay all the interconnection costs that are “identified by the electric public utility” and would be compensated for the electricity supplied by the utility, according to the bill.

Committee Chair Bob Smith (D) said the bill, “in a nutshell, in some ways allows interconnectors to skip the PJM process.” He added, however, that he is “not 100% sure of that.”

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said the bill would provide an alternative to the extensive delays experienced by projects in seeking interconnection through PJM’s process.

“We’ve got projects that are viable, that are just sitting there waiting,” he said. “And so all this bill does is, it says, ‘Hey, if the public utility has jurisdiction over the line, and if we meet all the requirements of the public utility … why shouldn’t they be able to approve it?’ We don’t necessarily need PJM at that point.”

Joseph Gurrentz, director of external affairs for the New Jersey Utilities Association (NJUA), said one question still to be resolved is whether the bill defines the “electric transmission and distribution system to apply only to the electrical systems within New Jersey,” and therefore under the jurisdiction of the Board of Public Utilities. If not, he said, the projects could “inadvertently butt up against the jurisdiction over regional transmission infrastructure” of FERC.

Asked for comment about the bill, PJM spokesman Daniel Lockwood said the RTO “has requirements to interconnect into the transmission system that have been approved by [FERC].”

“Whether a prospective resource is required to follow that process depends on the size of the resource and where it wants to interconnect,” he said. “All of our states have their own interconnection processes, as some resources interconnect into the grid that is overseen at the state level.”

Like all grid operators across the U.S., PJM has an interconnection queue clogged with proposed renewable resource projects. FERC approved a PJM proposal to overhaul its interconnection queue process in late 2022; the commission then issued Order 2023 last July, which required grid operators to revise their processes to include a “first-ready, first-served” cluster methodology, among other changes.

PJM in May told FERC the RTO’s new commission-approved process already complies with Order 2023, as it “parallels many reforms PJM has already implemented” (ER24-2045). It argued it was eligible for “independent entity variations” under the rule. (See PJM Reaches Milestone on Clearing Interconnection Queue Backlog.)

But on June 20, several clean energy and environmental organizations filed joint protests against PJM’s compliance filing.

“PJM stretches the meaning of the ‘independent entity variation’ beyond any reasonable interpretation or application,” argued one group that included the American Clean Power Association. “Should the commission accept the compliance filing, PJM would completely avoid compliance with significant portions of” Order 2023.

“The queue is so badly backlogged that PJM is not reviewing any new applications — and will not do so until 2026 at the earliest,” said another group that included the Natural Resources Defense Club. “At the same time, PJM is sounding the alarm about a reliability crisis because new generation cannot come online quickly enough to replace retiring power plants.”

But “PJM resists reform to its interconnection process. PJM proposes very few changes to comply with Order No. 2023, and the few changes it proposes do not meet the order’s rigorous standards.”

The RTO has not stopped accepting applications, Lockwood said, but new interconnection requests “will be studied starting in 2026 as we move the previously existing projects through the process.”

Other State Efforts

The New Jersey bill follows other efforts by the state to improve and speed up the interconnection process for renewables as it strives to meet its aggressive clean energy goals.

The state is seeking to install 12.2 GW of solar energy by 2030; it had about 4.85 GW of installed solar capacity at the end of April, according to the latest figures publicized by the BPU.

The BPU on April 30 approved a package of rules designed to streamline the utility interconnection application process. Part of it included enabling applicants to get an early indication of the project feasibility and costs. (See New Jersey Opens 4th Offshore Wind Solicitation.)

At the senate committee hearing June 20, NJUA’s Gurrentz said the organization was “not taking a position on the bill today,” but it is concerned that [it] could detract from some of the progress that’s gone on at the BPU and ship the application backlog that existed at PJM to a similar problem at home at our utility companies.” Another concern is the requirement to handle “very large” solar projects, up to 20 MW.

“Undertaking these studies to determine the impact of such large interconnections on power quality, reliability and the stability of the electrical grid will take time, and it may divert time and resources that could be spent elsewhere,” he said.

Gurrentz was the only person to testify in person on the bill, but it drew written expressions of support from Environment New Jersey, the New Jersey Division of Rate Counsel, the Mid-Atlantic Solar Energy Industries Association and the New Jersey Sustainable Business Council.

June 25, 2024July 2, 2024

Texas PUC Adds OPUC’s Hjaltman as 5th Commissioner

Texas’ Public Utility Commission is back to its full five-commissioner complement with the appointment of Courtney Hjaltman, CEO of the Office of Public Utility Counsel (OPUC) since 2022.

Texas Gov. Greg Abbott named Hjaltman to the PUC on June 24 for a term that expires Sept. 1, 2025. She fills the seat left vacant by Will McAdams, who stepped down from the PUC in December to focus on his family and health.

Abbott said Hjaltman’s service to the state and her legal expertise makes her the “ideal choice” to serve on the commission. “Courtney will ensure that Texans in every corner of our state have access to quality utility services for years to come,” he said in a statement.

As OPUC’s CEO, Hjaltman advocated for Texas’ residential and small commercial customers. During the ERCOT Board of Directors’ meetings June 17-18, she voted against a protocol change revising an ERCOT ancillary service over concerns it would raise consumers’ rates. That likely means she will have to recuse herself when the PUC considers the protocol change.

Hjaltman was Abbott’s deputy legislative director when she was appointed to OPUC and has more than 17 years of state service, much of it in the legislature. She holds bachelor’s degrees in in both corporate communications and government from the University of Texas and is a graduate of the governor’s Executive Development Program at UT’s Lyndon B. Johnson School of Public Affairs.

State lawmakers increased the size of the PUC from three commissioners to five after the disastrous and deadly 2021 winter storm. The three incumbents at the time lost their jobs in the storm’s aftermath.

June 25, 2024June 26, 2024

Report: Industrial Electrification Should Focus on ‘Easy to Abate’ Sectors

The U.S. could ramp up the electrification of heavy industry by 50%, reduce the sector’s fossil fuel use by 25% and cut its greenhouse gas emissions by 100 million metric tons per year by 2030, according to a new report from Schneider Electric’s Sustainability Research Institute.

But hitting those ambitious targets will require a shift of focus, the report says. Instead of prioritizing long-term solutions for the hardest-to-abate industries, such as petrochemicals, oil and coal, a different approach could zero in on the lower-hanging fruit of individual processes that can be electrified with existing technologies and without major changes to production.

“Emissions are not all equal,” the report says. “Those that can be reduced more rapidly hold much greater value than those that could be reduced in the future (even if massive).”

Pushing toward President Joe Biden’s goal of reducing the nation’s GHG emissions by 50 to 52% from 2005 levels by 2030, the U.S. has focused on electrification of transportation and buildings via incentives in the Inflation Reduction Act. But industrial electrification varies from sector to sector, the report says.

Electric arc furnaces are widely used in steel production, but options for electrifying the high-temperature process heat needed for chemicals and oil and gas refining still are in the demonstration phase, according to the Department of Energy’s recent Pathways to Commercial Liftoff: Industrial Decarbonization report.

Industry accounts for about 23% of U.S. greenhouse gas emissions, according to EPA. The Schneider report notes that five sectors ― chemicals, petroleum and coal products, primary metals, nonmetallic minerals and paper ― make up close to 75% of that total.

Traditional approaches to industrial decarbonization require that certain hard-to-abate industries continue to rely on natural gas or other fossil fuels to produce the high heat they need, until alternative technologies such as green hydrogen, carbon capture and sequestration, and small modular reactors can be commercialized at scale.

The report cites 2020 research from the California Energy Commission suggesting that building electrification could drive a switch away from natural gas and a decrease in the customer base, driving up natural gas prices for buildings and industry. Natural gas prices for industry could double by 2030, the CEC report predicts.

“This is particularly relevant in the context of rapid relocalization of a number of industries in the country,” the Schneider report says. “Will these new facilities be built for a net-zero world, relying on alternative and sustainable energy resources, or will they be connected to the existing natural gas grid and perpetuate reliance on fossil fuels?”

To move toward electrification, the report breaks down industrial energy use and emissions into subprocesses ― direct and indirect, process and nonprocess ― and identifies which could be electrified quickly in the coming decade. For example, most nonprocess energy use ― that is, energy not used for manufacturing but for building operations such as lighting and space heating and cooling ― could be rapidly electrified with existing technologies.

A second phase of industrial electrification would include the technologies currently being demonstrated but not yet deployed at commercial scale, especially for targeted processes in sectors such as food and beverage, textiles and electrical equipment, the report says.

Of the 21 industrial sectors analyzed in the report, the combination of the first and second phases could push eight to 80% electrification and 16 to at least 60% within a decade.

The report notes that half the reductions in fossil fuel use and GHG emissions will come from “easy to abate” industrial sectors, rather than hard-to-abate processes.

The report acknowledges the reduction in fossil fuel use will increase electricity demand ― by about 300 TWh per year ― but assumes that this new demand would be met with the wind, solar and storage sitting in interconnection queues across the country, providing additional efficiencies and emission reductions.

Getting the Finances Right

Beyond 2030, a third phase of industrial electrification would require innovative technologies still in development, such as electric “cracking” furnaces used in the production of petrochemicals and other electric furnaces, the report says.

Such innovations could drive industrial electrification to 64% across sectors, with 14 sectors hitting 80%, the report says.

“This major opportunity challenges the current hard-to-abate-centric approach to industrial decarbonization, which suggests little is achievable until new innovations deploy at scale.”

The obstacles ahead include a lack of information about the potential benefits of industrial electrification, getting the finances right and “grid reinforcements, which take several years to materialize.” The report provides general, mostly familiar recommendations.

To raise public and industry awareness, the report proposes the launch of dedicated state offices or clearinghouses to advance industrial electrification.

Getting the finances right will require making the cost of electrification competitive or at least comparable with natural gas, through tax incentives but also new approaches to electricity rate-setting, including time-of-use rates, to promote system flexibility.

Grid modernization and expansion will take time and will “come at the expense of natural gas grids and their associated revenues,” the report says. “This also requires a specific policy focus to ensure a smooth transition.”

June 24, 2024

FERC Preparing Multiple NERC Decisions

ERO Enterprise stakeholders will be closely watching FERC’s open meeting this week for updates on several items related to NERC and its reliability standards.

NERC’s proposed cold weather standard EOP-012-2 (Extreme cold weather preparedness and operations) is among the topics the commission might be deciding at its meeting (RD24-5). The ERO submitted the standard for approval in February after NERC’s Board of Trustees approved it.

FERC ordered NERC to develop the new standard last year to replace EOP-012-1, which the commission approved last year while noting numerous “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods” that must be addressed before EOP-012-1 takes effect this October. (See FERC Orders New Reliability Standards in Response to Uri.)

The replacement standard has met some criticism from stakeholders: This year, the ISO/RTO Council (IRC) expressed “united opposition” to EOP-012-2 and called on FERC to remand the standard back to NERC for revision. In its comment, the IRC said NERC’s proposed requirements were “subjective [and] unclear,” for example by excusing generator owners from implementing freeze protection measures by claiming a “cold weather constraint,” or by granting overly generous exemptions for existing generating units.

NERC dismissed IRC’s objections in an April filing, indicating that its drafting team had aimed to “provide a high bar for generators that operate in cold weather” while addressing concerns that overly stringent requirements could push generator operators to not use their facilities in cold weather at all.

Assessment Proposal Still Under Consideration

Also on FERC’s agenda is the commission’s proposal to require NERC to submit performance assessments every three years, shortening the timeline from the five-year cycle currently in effect (RM21-12).

FERC suggested the shortened time frame in 2021, saying a quicker turnaround would “provide better continuity” in the commission’s oversight of the ERO Enterprise and its ability to identify potential performance improvements more quickly. The Notice of Proposed Rulemaking was issued alongside an order for NERC to audit the compliance monitoring and enforcement programs of all regional entities. (See FERC Orders Audits of All REs by 2023.)

NERC and the REs pushed back on the commission’s plan, claiming they would “place a burden on ERO Enterprise staff … that would outweigh any potential benefits.” Specifically, respondents warned of the time required to coordinate with REs, incorporate stakeholder feedback and gain approval from NERC’s board, and said adhering to a shorter time frame could prevent the ERO from reviewing the breadth of topics that it normally does in its assessments.

In this year’s draft performance assessment posted for comment in April, NERC suggested that FERC terminate the proceeding. The most recent filing in the docket was from the Western Interconnection Regional Advisory Body in 2021, endorsing FERC’s proposed three-year timeline.

FERC Considering IBR Rule Changes

The final ERO-related item in FERC’s agenda is NERC’s proposed updates for its Rules of Procedure relating to registration of inverter-based resources (RR24-2).

NERC developed the ROP changes last year as stage 1 of its three-stage registration process approved by FERC in May 2023. They will revise the definitions of generator owner and operator to create a new category, GO-IBR, for entities that own or operate IBRs that either have or contribute to an aggregate nameplate capacity of at least 20 MVA and are connected to a common point of connection with a voltage of at least 60 kV.

If FERC approves NERC’s ROP changes this week, the ERO’s next step will be to identify candidates for GO-IBR registration by May 2025, and then to register GO-IBRs by May 2026.

June 24, 2024June 25, 2024

Stakeholders Call on CAISO to Take Larger Role in Reliability Planning

CAISO stakeholders are calling on the ISO to take a bigger role in reliability planning because of the increasingly complicated nature of ensuring reliability on the California grid in the face of climate change.

“At this point in time, we have arguably five different agencies involved in keeping the lights on in California,” Carrie Bentley, CEO of Gridwell Consulting, said on behalf of the Western Power Trading Forum (WPTF) during a June 18 presentation to the ISO’s Resource Adequacy and Program Design Working Group.

Key among those other agencies are California’s Public Utilities Commission, Energy Commission and Department of Water Resources, which manages the state’s strategic energy reserve.

“We have overlapping processes that are only getting more complex over time. The coordination and processes are growing more complex because the state is not only trying to accommodate climate change, [and] plan for climate change, but it’s also trying to prevent climate change,” Bentley said.

Because no single agency is in charge of ensuring “holistic” reliability, Bentley proposed that CAISO take on that role and, more specifically, conduct probabilistic loss-of-load-expectation (LOLE) modeling to better understand the aggregate impact of the changing climate on grid conditions.

“This [LOLE modeling] actually allows you to say, ‘What are the impacts of all of these probabilities, all these different extreme events, and these different levers being pulled on by different agencies? What is the aggregate impact on the CAISO balancing area?’ And the only way I know to do that robustly is through loss-of-load-expectation modeling,” Bentley said.

In addition to driving up peak load, higher temperatures are also causing “astronomical” increases in load variability, Bentley said. Between 2017 and 2023, that variability was significant enough to cause load forecasts to deviate from actual loads by several thousand more megawatts than historically normal.

Planning processes must account for increases in variability to ensure reliability, Bentley said. And because resource planning is conducted over so many different agencies and processes, it is unclear if processes are “calibrated for climate change” or if “CAISO’s balancing area is actually reliable,” she added.

“There is a clear and present need for not just re-evaluation of individual processes for climate change, but also to do this holistically. And we think CAISO is uniquely suited to provide this function. In fact, we think CAISO is probably the only agency that will be able to provide this function because they’re the only ones with a clear picture,” Bentley said.

Bentley also called on CAISO to update counting rules and the planning reserve margin (PRM).

Other stakeholders expressed support for Bentley’s suggestions.

“This resonates incredibly … and is something we deeply need,” Cathleen Colbert, senior director of Western markets and policy at Vistra, said during the meeting. “We need to understand, what is the reliability status of the balancing authority area on a forward-looking probabilistic basis?”

Aditya Jayam Prabhakar, director of resource assessment and planning at CAISO, reassured stakeholders that the ISO is already working to address Bentley’s two main requests: to evaluate forward CAISO reliability assessments in terms of LOLE modeling, and to update default PRM and RA counting rules.

WPTF also requested that the ISO establish a comprehensive mothball and retirement process for generating plants based on local needs, but Bentley emphasized that the LOLE modeling should first be “stood up, and then it will naturally flow into other processes.”

June 24, 2024June 25, 2024

PUCN Sets Framework for NV Energy’s EDAM Participation

As NV Energy moves forward with plans to join CAISO’s Extended Day-Ahead Market, Nevada regulators have laid out a framework for how the company can seek approval for EDAM participation.

NV Energy should make the request through an amendment to the company’s energy supply plan, according to an order the Public Utilities Commission of Nevada (PUCN) approved June 21. NV Energy used a similar process in 2014 to get PUCN approval for joining CAISO’s Western Energy Imbalance Market (WEIM).

And as part of its request, NV Energy should address a long list of questions posed by the PUCN, ranging from the costs to join a day-ahead market to how participation will impact revenues and rates and what a path to an RTO would look like.

A Nevada law adopted in 2021 requires transmission providers in the state to join an RTO by January 2030.

The PUCN opened a docket in October 2023 to explore regional market activities in the Western Interconnection.

Commissioner Tammy Cordova, the presiding officer in the case, held three workshops this year on day-ahead market participation and invited two rounds of stakeholder comments. The workshops looked at cost-benefit studies and market design for the two competing Western day-ahead markets: CAISO’s EDAM and SPP’s Markets+.

Meanwhile, NV Energy recently stated its intent to join EDAM and provided some of the rationale for its decision in its 2025/27 integrated resource plan filed May 31. (See NV Energy Confirms Intent to Join CAISO’s EDAM and Market Footprint Critical for EDAM Decision, NV Energy Says.)

The company expects to file a request to join EDAM this year.

The announcement came after a Brattle Group study this year projected that NV Energy’s benefits under EDAM would range from $62 million to $149 million in 2032, depending on the market footprint, whereas Markets+ benefits would range from a $17 million loss to a $16 million gain.

During the commission’s June 21 meeting, Cordova said the cost-benefit analyses are just one factor to consider in a day-ahead market choice.

“It was really important to me that we had information beyond just production-cost modeling when we would evaluate whether or not any request by NV Energy was in the public interest,” Cordova said.

In a request to join a day-ahead market, the commission wants to hear about the market’s governance and who else plans to join.

Other questions focus on the resiliency of the market to natural disasters or cybersecurity threats. PUCN wants to know how GHG emissions will be tracked and the impact on compliance with the state’s renewable portfolio standard.

Another issue is the impacts on non-jurisdictional transmission customers in NV Energy’s balancing authority area.

Other questions are the impact of joining a day-ahead market on generation development and on building new transmission.

In written comments, PUCN staff said NV Energy should be required to address “whether the potential $5 [billion] to $10 billion of transmission investments proposed for Nevada will be impacted depending on which [day-ahead market] NV Energy requests to join.”

Staff pointed specifically to the Cross-Tie, SWIP-North, One Nevada No. 2 and TransWest projects.

In comments filed May 30, NV Energy expressed support for the list of questions.

“Examination of these areas will provide a comprehensive assessment of the potential benefits associated with DAM participation in general and of specifically joining the EDAM,” the company said.

Following approval of its order June 21, the commission is largely wrapping up the day-ahead market portion of the docket.

But in a second phase of the docket, the PUCN will be taking a closer look at RTO participation. A schedule for the RTO phase of the docket has yet to be established.

“This docket is by no means done,” Cordova said.

June 24, 2024June 25, 2024

Order Expected on Complaint Against PJM over ELCC Resource Accreditation

FERC is expected to issue an order during its June 27 open meeting on a complaint alleging PJM violated its Reliability Assurance Agreement (RAA) when accrediting intermittent resources (EL23-13).

Filed in November 2022 by economist Roy Shanker, the complaint argues the RTO improperly included energy above intermittent resources’ capacity interconnection rights (CIRs) when determining their capacity contributions. The practice was used for resources accredited through PJM’s effective load-carrying capability (ELCC) approach.

The commission issued a March 2023 order accepting a PJM proposal intending to resolve the issue by modifying the ELCC analysis to cap the hourly output a resource is expected to be able to offer at its CIR level (ER23-1067). The commission also is slated to issue an additional order in that docket June 27. (See FERC Approves Revisions to PJM’s ELCC Accreditation Model.)

The month prior to FERC’s order granting PJM’s proposal, Shanker argued against PJM comments asking the commission to dismiss his complaint, saying that even if the proposal resolved RAA violations going forward, that would not cure past violations.

The complaint asked the commission to adjust prior Base Residual Auction settlements “that are not time barred” and effectively implement its proposed cap on hourly output immediately without a transitional period. It requested an effective date of Nov. 30, 2022, and refunds through the implementation of PJM’s proposal.

June 24, 2024June 25, 2024

FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations

FERC has established settlement judge procedures to consider the validity of rate schedules filed by Talen Energy to continue operating its Brandon Shores and H.A. Wagner generators past their retirement date (ER24-1787, ER24-1790). (See PJM Requests 2nd Talen Generator Delay Retirement.)

The commission’s June 17 order states that the proposed rate schedules may not be just and reasonable because of the calculation of the filings’ valuations of the two generators. It also took issue with adjusting fixed operating and maintenance expenses for inflation using an escalation index, along with the proposed monthly project investment tracker payment and performance requirements.

“While we are setting these matters for a trial-type evidentiary hearing, we encourage the parties to make every effort to reach settlement before hearing procedures commence,” the order states.

The filings requested annual fixed costs of around $175 million to keep Brandon Shores’ 1,273-MW coal-fired generator online from June 1, 2025, through Dec. 31, 2028, as well as variable costs such as fuel and $29.9 million in project investments. The Wagner filing requests $40.3 million annually to keep two of Wagner’s oil-fired units, amounting to 702 MW, online for the same period and $4.5 million in additional investments.

The reliability-must-run (RMR) agreement is intended to keep the generators online to avoid reliability violations identified throughout the Baltimore region while transmission reinforcements are constructed that would allow the units to deactivate without issue. (See FERC Approves Cost Allocation for $5 Billion in PJM Transmission Expansion.)

The proposed rates were opposed by the Independent Market Monitor and the Maryland Public Service Commission, who argued the rate schedules would improperly include sunk costs incurred prior to the start of the RMR term and unrelated to the going-forward costs of keeping the facilities operational.

The Monitor argued that including sunk costs that have already been reported as impaired assets would ask ratepayers to make investors whole for past losses.

The June 17 order accepted the rate schedules, suspended them and initiated the settlement judge procedures with the possibility of evidentiary hearings if that avenue does not yield a consensus.

Maryland Deputy People’s Counsel William Fields said sunk costs make up a significant portion of the proposed rates and the Office of People’s Counsel is preparing an analysis on how the RMR could affect state ratepayers. He said the office is pleased with the commission’s decision to open settlement judge procedures and plans to fully participate.

“We don’t view those as costs that are related to going forward with operations of the plant.”

Fields said he believes PJM’s backlogged generation interconnection process leaves few alternatives to expensive RMR contracts to keep retiring resources online while major grid reinforcements are constructed.

“We’ve got a few concerns with that approach or reliance on the market response here, and one is that this happens very quickly. You’re talking months, and that is very, very quick for any kind of significant market response to a significant, pretty big retirement. Trying to respond to that with a lot of megawatts is going to be difficult in any circumstance, and right now, the PJM queue process is working through its backlog, and that makes it even more difficult for some kind of new resource to get through and get online on a time frame that’s going to help the situation at all,” he said.

Protesters also disputed the filings’ methodology for determining the value of Brandon Shores and Wagner, depreciation and the amount of risk the company faces in continuing to operate the generators.

Monitor Joe Bowring said opportunity costs similar to those Talen is seeking to include in the rates have been rejected by the commission in past RMR filings.

The Brandon Shores filing also notes it’s subject to a settlement agreement with the Sierra Club requiring that coal combustion at the site cease by the end of 2025. It states that it will seek changes to those terms to allow the generator to keep operating for the RMR term.

Casey Roberts of the Sierra Club said the organization is willing to engage with Talen on the agreement, but “additional protections for the local community and consumers, and longer-term reforms to avoid similar predicaments in the future, must all be on the table.”

The club’s protest of the rate schedule also urged the commission to not approve an RMR agreement that would pay for Brandon Shores to remain online until the agreement has been modified to allow the generator to operate.

“Thus, it appears on the face of the CORS [continuing operations rate schedules] that Talen intends not to operate Brandon Shores under the CORS unless its settlement agreement with Sierra Club is modified, notwithstanding the hundreds of millions of dollars in fixed monthly payments that Talen would receive even if it never generates a single megawatt hour. FERC cannot approve such an arrangement, particularly on the expedited basis that Talen seeks in this proceeding,” the Sierra Club wrote.

Both the Sierra Club and Maryland Public Service Commission argued that the proposed rates lack performance requirements and would require load to pay significant sums to keep the two generators operational with no guarantee they would respond if dispatched by PJM.

Maryland PSC spokesperson Tori Leonard said the commission supports FERC’s directive opening the settlement judge proceedings.

“FERC’s preliminary analysis confirmed that both the Brandon Shores rate schedule and Wagner rate schedule have not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” Leonard wrote in an email. “This commission is pleased that FERC granted our request (as well as the request of the Maryland Office of People’s Counsel), to set the matter for settlement judge procedures. The commission will continue to advocate for a reasonable resolution of the Brandon Shores and Wagner RMR filings that will minimize impacts to ratepayers, while preserving the reliability of the bulk electric power system to serve Maryland’s needs.”