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November 5, 2024

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PJM Reaches Milestone on Clearing Interconnection Queue Backlog

PJM on May 20 announced that it had completed the first phase of studies for 306 generation interconnection requests sorted into the first cycle in the transition to its new interconnection process, a cluster-based study approach intended to reduce how long it takes the RTO to bring generators online. 

“This is another critical milestone for PJM’s widely supported interconnection process reform,” said Aftab Khan, executive vice president of operations, planning and security. “New service requests for generation resources are moving through our process as designed and promised, with more than 200,000 MW of projects to be studied over the next two years to help states advance their energy policy goals.” 

Developers with projects in Transition Cycle 1 (TC1) will have 30 days to review the system impact studies and decide whether to move forward with their projects to the facility study phase. PJM said those that complete the process will be ready for construction by mid-2025. (See PJM Initiates Transitional Interconnection Queue.) 

Another 306 projects expected to require minimal network upgrades are being studied through an Expedited Process “fast lane” that is expected to yield final interconnection service agreements (ISAs) throughout this year. PJM also plans to initiate Transition Cycle 2 on June 20, with a likely application deadline by Dec. 16. 

PJM said about 72 GW are expected to clear the queue by mid-2025 and 230 GW over the next three years, more than 90% of which is renewable energy or storage. 

The cluster-based approach groups projects together on a first-ready, first-served approach to identify any grid upgrades and assign costs. It also includes increasingly large readiness deposits to be made throughout the study process, with the aim of discouraging speculative or uncertain projects from taking focus away from others. PJM said 118 projects have dropped out of the queue or failed to post deposits, out of 734 eligible. (See FERC Approves PJM Plan to Speed Interconnection Queue.) 

Environmental organizations said the milestone is a welcome first step but that more change is needed. 

“PJM worries there’s not enough new power coming online, but it’s still only approving projects proposed four to six years ago,” said Tom Rutigliano, of the Natural Resources Defense Council. “This is a step forward, but PJM’s current process is not enough to get these new clean energy projects connected to the grid as quickly as they’re needed.” 

Christine Powell, deputy managing attorney at Earthjustice, said the amount of time it has taken for PJM to get to this stage has already resulted in projects stalling or withdrawing from the queue. “While PJM’s shift to a cluster study process is a positive development for the hundreds of clean energy projects waiting to interconnect to the power grid, PJM continues to lag behind other RTOs,” she said. 

Katie Siegner of RMI pointed to a study released in February that found that incorporating grid-enhancing technologies (GETs) into how PJM conducts transmission planning could optimize the use of existing infrastructure to reduce upgrades needed for new projects and speed interconnection studies. The study estimated that about $1 billion in annual production costs could be avoided through 2033 by expanding use of GETs. (See RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions.) 

PJM’s “clearest opportunity for improvement is bringing its interconnection process into compliance with Order 2023, particularly through serious consideration of alternative transmission technologies that could provide faster and cheaper network upgrade alternatives,” Siegner said. “The fact that no grid-enhancing technologies have been identified or used as network upgrades to date suggests PJM has more work to do in incorporating these fast, flexible transmission tools into its study methodologies.” 

PJM spokesperson Jeff Shields told RTO Insider the RTO allows and welcomes GETs as components of proposals for its Regional Transmission Expansion Plan and laid out how it will fully comply with Order 2023’s requirements around their facilitation in its May 16 compliance filing (ER24-2045). 

“All of the enumerated [GETs] already are considered and studied as necessary, if merit exists in the use of such technologies, in the course of interconnection studies in the PJM region,” Shields said. “This incorporation of new and emerging technology is consistent with the objectives of the final rule, which requires transmission providers to evaluate certain GETs in each and every one of its interconnection studies.” 

Shields said PJM agrees there is more progress to be made in improving generator interconnection and development, both at the RTO and removing external obstacles. “We are working with stakeholders within the PJM stakeholder process, as well as entities outside of the PJM membership, to accomplish this.” 

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FERC Directs ISO-NE to Submit Another Order 2222 Compliance Filing

Responding to a rehearing request by Advanced Energy United over FERC’s partial acceptance of ISO-NE’s third Order 2222 compliance filing, FERC has directed ISO-NE to submit an additional filing to specify its metering and telemetry practices for distributed energy resource aggregations (DERAs) (ER22-983-006). 

Order 2222, which requires RTOs to update their tariffs to enable DERAs to participate in wholesale markets, has led to a long series of compliance filings and rehearing requests related to ISO-NE’s compliance.  

FERC accepted ISO-NE’s fifth compliance filing April 11, subject to further compliance. (See Still More Work for ISO-NE on Order 2222 Compliance.) 

On May 23, FERC issued an order on rehearing responding to Advanced Energy United’s challenge of ISO-NE’s third compliance filing, which FERC accepted Nov. 2, 2023. (See FERC Accepts ISO-NE Order 2222 Compliance Filing.) 

“We sustain three of the four findings AEU [Advanced Energy United] challenges,” FERC ruled.  

Responding to the trade association’s argument that ISO-NE’s three metering options for DERAs — “retail delivery point metering, submetering with reconstitution and parallel metering” — are unnecessarily prohibitive, FERC affirmed its finding that these options “do not pose an unnecessary or undue barrier to individual DERs joining an aggregation.” 

FERC upheld its acceptance of ISO-NE’s proposal to apply the requirements of the “binary storage facility” and “continuous storage facility” participation models for DERAs to provide withdrawal service. FERC also continued to find that the ISO-NE properly explained the steps it took to “avoid imposing unnecessarily burdensome costs on DER aggregators and individual resources in DERAs.” 

However, FERC set aside its prior ruling that ISO-NE adequately described its metering requirements for DERAs.  

“Specifically, we set aside our finding that, for those DERAs containing behind-the-meter DERs, ISO-NE’s tariff includes a basic description of the metering practices for DERAs with references to specific documents that contain further technical details for metering and telemetry practices,” FERC wrote.  

“ISO-NE’s basic description of its metering practices for DERAs is incomplete because its tariff does not include submetering requirements for DERAs participating as submetered Alternative Technology Regulation Resources,” FERC added. 

FERC directed ISO-NE to submit an additional compliance filing to specify these submetering requirements. FERC also set aside its ruling that ISO-NE’s proposal to extend “existing requirements for Alternative Technology Regulation Resources to DERAs” is just and reasonable, writing that it will reassess these requirements after the RTO submits its additional compliance filing.  

Caitlin Marquis of Advanced Energy United said FERC’s directive “sends ISO back to the table to resolve one metering barrier for DERs seeking to provide regulation service, which is welcome and important.” 

“However, as New England and the rest of the country face rising demand, rising electricity prices and reliability threats, much work remains to ensure the region is taking full advantage of DERs,” Marquis added. 

Commissioner Mark Christie concurred with the parts of the order that accepted ISO-NE’s filing and dissented “to the rest.” 

Christie decried Order 2222’s “seemingly never-ending and avoidable rounds of compliance filings” and called the compliance saga a waste of time and money. 

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FERC to SPP: Show More Work on PRM Determination

FERC on May 23 found SPP’s tariff revisions laying out how it determines its planning reserve margin (PRM) methodology only partly met the commission’s order on rehearing and directed an additional compliance filing within 30 days (ER24-1221). 

The commission said SPP complied with its directive to include a timeline for making changes to the PRM before a planning year in its tariff. But it also said the RTO failed to include further information on how it uses its loss-of-load expectation studies to determine the PRM. 

FERC accepted SPP’s tariff revisions effective April 10, subject to further compliance. 

The commission rejected protests from the grid operator’s members that SPP provide three years’ notice before increasing the PRM and that it be prohibited from adopting near-term increases without demonstrating that the market has capacity surplus available for purchase. The commission found both arguments to be outside the compliance proceeding’s scope, saying its directive only required the timeline for making PRM changes. 

The RTO said it will perform an LOLE study at least biennially to determine whether a PRM change is needed and post the results. Staff will then provide a recommendation for any changes, with the Board of Directors and state regulators approving the change. The tariff revisions place additional restrictions on any approved PRM that exceeds the current value or the value identified in the final LOLE results by 1% or more; any PRM increase would be implemented for the planning year, beginning at least one year after approval. 

SPP’s board in 2022 approved changing the PRM to 15% from 12% over opposition from stakeholders advocating a three-year phase-in. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.) 

FERC last year rejected a complaint by SPP members seeking to overturn the decision. In a 3-1 vote, the commission ruled that American Electric Power, Oklahoma Gas and Electric, and Xcel Energy failed to show SPP’s PRM process was unjust, unreasonable or unduly discriminatory because the figure itself was not included in its tariff. (See FERC Rejects Protest of SPP PRM Increase.) 

AEP, OG&E and Xcel filed a rehearing request with FERC, but the commission took no action on it. They then filed a petition for review with the 8th U.S. Circuit Court of Appeals in July 2023; that proceeding has been held in abeyance pending SPP’s compliance filing following a successful FERC motion (23-2734). 

FERC found in September 2023 that SPP’s proposal failed to “adequately” explain how it would account for the LOLE study’s results or any additional considerations when determining the PRM, and that the tariff did not adequately explain the timeline for the RTO’s PRM reviews (EL23-40-001). FERC ordered a compliance filing within 60 days, but SPP and the protesting companies jointly requested an extension to February, which the commission granted. 

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ERCOT Projects 97-GW Peak Demand by 2034

[EDITOR’S NOTE: This story has been updated to reflect ERCOT’s new unofficial peak demand record for the month of May, set May 27. The previously reported mark for the day was 73.75 GW.]

ERCOT’s latest capacity, demand and reserves (CDR) report projects summer peak demand will increase to more than 97 GW by 2034, assuming normal weather conditions. 

However, the weather has been anything but normal recently in Texas. ERCOT is coming off the second-hottest summer in state history, and it just set an unofficial peak demand record for May (77.13 GW) that exceeds the grid operator’s all-time peak from 2018 (73.47 GW). 

One Austin resident’s weather projection for the summer. | Emily Eby French via X

The heat index hit 113 degrees Fahrenheit in Austin on May 25 and has already hit triple digits in Houston, where the low temperature dropped to only 80 degrees on May 21. That is about a month and a half ahead of normal, according to a local forecaster. 

The National Oceanic and Atmospheric Administration (NOAA) has predicted an “above-average” hurricane season this year, with between 17 and 25 named storms. It says “extraordinarily high, record-warm water temperatures” in the Atlantic Ocean, linked to climate change, are energizing the waters and fueling storm development.  

NOAA said another factor influencing this year’s hurricane season is La Niña, a climate pattern that cools surface ocean temperatures and lessens wind speeds, allowing more storms to develop. 

The CDR report forecasts peak demand of 83.29 GW this summer, assuming normal weather conditions. Demand is expected to exceed 84 GW in 2026, 86 GW in 2028 and 90 GW in 2030, according to the report. 

Energy consultant and Stoic Energy principal Doug Lewin doesn’t think that is enough. He says ERCOT still doesn’t factor climate change into its projections, and he noted the ISO’s current record for peak demand is 85.46 GW, registered last August.  

“They only expected 73 GW this month and we’ve already passed that. Had this heat hit outside a holiday weekend, we’d likely be around 80 GW,” he said on X, the social media platform formerly known as Twitter. 

ERCOT says its load forecasts are based on normal weather conditions and determined by the methodologies posted to its website. Staff forecasts scenarios through 2033 using a model with historical weather years. 

The CDR report is designed to provide forecasted planning reserve margins (PRMs) for ERCOT’s summer (June-September) and winter (December-February) peak-load seasons. The ISO says it is not intended to characterize the risk of scarcity conditions from a real-time operations perspective. It defines the PRM as the percentage of capacity above firm demand that is available to cover uncertainty in future demand, generator availability and new resource supply. 

ERCOT’s operational capacity exceeds 100 GW next year but increases to only 101.50 GW by 2033. However, the CDR report indicates the grid operator expects 30 GW of planned capacity by that same time, with solar resources accounting for 28 GW. 

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BOEM FEIS Cites ‘Major’ Impact from NJ OSW Project

The Bureau of Ocean Energy Management released its final environmental impact statement (FEIS) May 23 that concludes that New Jersey’s foremost offshore wind project, Atlantic Shores, would have a “major” impact on commercial and for-hire recreational fishing, the view from the shore and on-ship traffic. 

The 560-page study found that the 200-turbine, 1,510-MW project would impact the commercial and recreational fishing sector through a range of activities, including anchoring, cable emplacement, noise, port use and structure presence. At about 10 miles from the shore, Atlantic Shores is the closest OSW project in development to the land in New Jersey. 

But the FEIS also concludes the area would suffer a major impact even if the project were not constructed. Those impacts would stem from factors including fishery management measures taken to ensure that the volume of fish caught is sustainable; the impact of climate change from ocean warming, sea level rise and ocean acidification; and non-OSW construction on land. 

Likewise, the study found that although the project would have a major scenic impact on the area — on the open ocean, seascape, and landscape character and views — the coast would suffer a strong scenic impact regardless because of onshore development and construction activities, offshore vessel traffic and the effects of other OSW projects. 

And the agency found that the impact of the project on most of the other 19 categories studied — including recreation and tourism, land use and costal infrastructure, water and air quality, and a variety of animal species — would be moderate or minor.  

BOEM compiles EIS reports to assess the potential impacts from an OSW project on physical, biological, socioeconomic and cultural resources. The final report informs BOEM’s decision on whether to approve, approve with modifications or disapprove the project’s Construction and Operations Plan (COP), and the FEIS may also be used by other agencies in evaluating the project. 

The FEIS evaluates the impact on the area if the project does not go ahead and if the project goes ahead as planned. The agency also looks at the impact if the project were reshaped or adjusted to try to mitigate any effects, such as by reducing the number of turbines or their position in the lease area. But any such adjustments did not generally reduce the impacts of Atlantic Shores that BOEM assessed as “major.” 

In response to the release of the FEIS, Atlantic Shores said it “remains dedicated to responsible development [and] environmental stewardship.” 

“We are encouraged to see forward progress and getting another step closer to delivering New Jersey’s first offshore wind projects,” said CEO Joris Veldhoven. “We appreciate BOEM’s thorough environmental evaluation and recognize the significance of this milestone.” 

Tourism, Whale Impact

Atlantic Shores, a 50/50 joint venture between EDF-RE Offshore Development and Shell New Energies US, was one of two projects — along with Danish developer Ørsted’s Ocean Wind 2 — that the New Jersey Board of Public Utilities approved in its second solicitation in 2021. That followed the agency’s approval in 2019 of Ørsted’s Ocean Wind 1 project. (See NJ Awards Two Offshore Wind Projects.) 

Ørsted has abandoned its two projects, saying they were no longer feasible. 

New Jersey approved two more projects in its third solicitation, and the combined total of those two and Atlantic Shores would, if completed, account for slightly less than half the state goal of 11 GW of OSW capacity by 2040. The state in April opened a fourth solicitation. (See New Jersey Opens 4th Offshore Wind Solicitation.) 

Critics of the projects are concerned about the impact on the commercial fishing and tourism sectors and on the quality of life to local homeowners, especially from an impaired view of the sea. 

The study also found the project would have only a minor impact on the tourism industry. 

Navigation and vessel traffic in the area would suffer only a moderate impact if Atlantic Shores were not built, but a major impact if it were because of “increased vessel traffic in and near the project area and on the approach to ports used,” according to the report. Traffic would especially increase during the construction period, and the impacts would include “changes to navigational patterns and to the effectiveness of marine radar and other navigation tools” that could result in “delays within or approaching ports, increased navigational complexity [and] detours to offshore travel or port approaches,” the study says. 

The study found the project would have only a moderate impact on most mammals but would have a major impact on the North Atlantic right whale, which is an endangered species. That assessment stemmed from the fact that “impacts on individual NARWs could have severe population-level effects and compromise the viability of the species due to their low population numbers and continued state of decline,” the report said. 

Opponents of OSW projects regularly cite a series of whale deaths on the Jersey Shore as potentially caused by preliminary OSW activities. But construction has yet to begin on any project in the state, and federal and state investigators have found no link between the deaths and OSW activities, saying they are most likely caused by vessels hitting the whales. 

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Texas Public Utility Commission Briefs: May 23, 2024

A CenterPoint Energy senior executive told Texas regulators May 23 that slightly more than 27,000 of its customers remain without power a week after a derecho devastated the Houston area with winds exceeding 100 mph. 

Jason Ryan, CenterPoint’s executive vice president of regulatory services and government affairs, said during the Public Utility Commission’s open meeting that the utility remains in emergency operations. 

“We understand that it’s been a long seven days, that it’s been in excess of 100 degrees in terms of the feels-like temperature and that we still have a lot of work to do,” Ryan said. “We will work day and night until we finish the mission. We appreciate all of our customers and for sticking with us through this unprecedented event.” 

He said CenterPoint had only about 15 minutes to prepare for the derecho, which national meteorologists define as a continuous or intermittent path of severe wind from a squall line of thunderstorms. Derechos can extend at least 400 miles and at least 60 miles wide and generate hurricane-force winds. 

About 922,000 CenterPoint customers were without power in the storm’s aftermath. That number was down to fewer than 18,000 following the PUC meeting, according to CenterPoint’s performance tracker. 

Ryan thanked the more than 5,000 mutual assistance crews from other states that augmented CenterPoint’s 2,000 crew members, noting they have not suffered any serious injuries or deaths. 

“That’s probably the proudest accomplishment that I can stress with you,” he told the commissioners. “I look forward to sending these crews home just as safe as they arrived to help our communities.” 

The restoration crews replaced more than 800 miles of wires, more than 700 transformers and about 2,000 distribution poles. CenterPoint said in a statement it has also deployed 13 mobile generators to critical facilities, cooling centers, health care facilities, first responder locations, senior centers and schools. 

“Everyone I’ve talked to has said you all have done an amazing job responding to an event that you couldn’t really prepare for,” PUC Chair Thomas Gleeson told Ryan. “I’ve heard nothing but good things.” 

Wearing a logoed polo shirt instead of his normal suit and several days’ worth of stubble, Ryan said he was returning to CenterPoint’s emergency operations center after his presentation. He said the company’s headquarters in downtown Houston lost more than 500 windows; officials say it could be months before the business district’s windows are repaired. 

“While we don’t know when we’ll have access to our building again, it hasn’t impaired our restoration efforts,” Ryan said. 

Loan Program Attracts Interest

PUC staff said they have received 10 completed commitments to apply for disbursements from the $5 billion Texas Energy Fund (TEF), which is designed to incent more dispatchable energy to the ERCOT grid. The proposed projects could add more than 4.9 GW of capacity (56455). 

Applicants face a May 31 deadline to file notifications that they intend to apply for the funds. Formal applications can be submitted on or after June 1. The loans will be issued by Dec. 31, 2025. 

The commission established the TEF in March because of state legislation passed last year. Qualifying projects must add at least 100 MW of dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

NRG Energy accounts for three of the applications. The company said this year that it plans to use TEF loans to help finance construction of two new natural gas-fired plants that would be available in 2026. 

Corona Named Executive Director

The commission announced it has promoted interim Executive Director Connie Corona to the official role. She fills the position vacated by Gleeson when he was appointed Texas PUC chair in January. (See Abbott Names PUC Executive Director as Chair.) 

“I don’t think it could be any question you’re the right person for this job,” Gleeson told Corona. 

Corona has spent 12 years at the commission, sandwiched around a 14-year stint in NRG’s regulatory affairs department. 

The PUC also promoted Chief Program Officer Barksdale English to deputy executive director. English joined the commission in 2018 after six years at Austin Energy. 

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FERC Accepts NERC’s New Cybersecurity Standard

FERC on May 23 approved NERC’s proposed reliability standard for protecting electronic communication between control centers, along with the ERO’s plan for collecting data on winterization of generating units. 

NERC began development on CIP-012-2 (Cybersecurity — communications between control centers) in 2020, following a directive from the commission upon the approval of its predecessor CIP-012-1 (RD24-3). At the time, FERC said the standard needed further changes to protect the availability of communications links and data as required by Order 822, the impetus for the original standard. (See NERC Reliability Standards Get FERC Approval.) 

The ERO submitted the new standard in January, promising that it “expands the protections required by … CIP-012-1 by requiring responsible entities to mitigate the risk” of lost communications between control centers, along with the loss of real-time intra-control center assessment and monitoring data. 

NERC said the applicability and scope of CIP-012-2 are unchanged from the current standard; all responsible entities that own or operate control centers will be required to comply, except for facilities that “only communicate real-time data with other control centers regarding a co-located field asset [such as] a transmission station or generation facility.”  

The only change from CIP-012-1 is the addition of two new parts to requirement R1. Part 1.2 requires entities to implement protections for the availability of data in transit between control centers, while part 1.3 mandates that entities have methods for recovering lost communication links.  

In a filing, FERC said the proposed standard was “just, reasonable [and] not unduly discriminatory or preferential,” and addressed the directives in its order. The commission approved NERC’s request for the standard to take effect on the first day of the first quarter that comes 24 calendar months after the effective date of the order; as a result, the standard will become enforceable on July 1, 2026. 

ERO Outlines Data Collection Proposal

NERC’s cold weather data collection plan arose from FERC’s order last year approving EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations). (See FERC Orders New Reliability Standards in Response to Uri.)  

The commission directed NERC to submit within 12 months a plan for gathering data on generating unit winterization; for performing an analysis of the risk posed by proposed technical, commercial or operational constraints in EOP-012-1; and for analyzing the “actual performance of freeze protection measures during future extreme cold weather events.”  

NERC provided its plan to the commission in a compliance filing in February, explaining that it intends to submit an annual informational filing to FERC covering the required information; the first such filing will be made Oct. 1, 2025. Data for this first filing will be collected through a Section 1600 data request. This will be done for the second filing in 2026, possibly accompanied by additional data requests under NERC’s Compliance Monitoring and Enforcement Program. 

Information to be required from data requests to generator owners includes: 

    • identity and location of generating units; 
    • identity and megawatts of generation of units for which owners have declared constraints under EOP-012, along with the constraint declaration type and rationale; 
    • megawatts of generation within the owner’s fleet that are currently capable of operating at the unit’s extreme cold weather temperature;  
    • projected megawatts for which the generator owners and operators expect to implement and complete corrective action plans each year; 
    • the number of generator cold weather reliability events experienced in the previous winter; and 
    • megawatts of generating units that might be susceptible to the causes of the previous winter’s cold weather events. 

In its filing this week, FERC noted that no interventions or protests were filed by the March 12 due date. The commission concluded that the proposal meets its directives, and approved NERC’s data collection plan. 

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FERC Forecasts High Temperatures, Flat Prices for Summer

This summer should bring high temperatures and electricity demand, but flat prices as cheaper fuel offsets higher load, according to FERC’s Summer Energy Market and Electric Reliability Assessment, released May 23. 

The National Oceanic and Atmospheric Administration forecasts a 60 to 70% likelihood of above-normal temperatures in June, July and August across the country compared with the 30-year average. 

“High temperatures that are widespread can intensify stressed conditions on the electric grid by creating high electricity demand across a wide geographic area and reducing the availability of imported electricity from neighboring systems because they are also experiencing high demand,” the report said. 

Following last summer’s “El Niño” weather pattern, the National Weather Service says there is a 69% chance that a La Niña could emerge this summer. For the U.S., a La Niña means more storms in the center of the country and less precipitation in the South; it can also lead to more Atlantic hurricanes. 

NOAA released its hurricane forecast May 23 as well; it predicts an 85% chance of an above-normal season, with 17 to 25 named storms, eight to 13 forecast to become hurricanes, and four to seven of those to be major hurricanes. Forecasters have a 70% confidence in the ranges. 

Despite expectations for a hot summer, electricity prices are forecast to be flat or slightly lower than in 2023. The one exception is the Northeast, where regional natural gas prices could mean higher power prices than last year. 

FERC is forecasting average ISO-NE prices to be almost $10/MWh higher than last year, while those in CAISO are expected to fall by $23 to $34/MWh. 

U.S. installed generation capacity is expected to hit 1,207 GW, up 40 GW from 2023 because of additions of wind and solar, while retirements were dominated by coal capacity, with 3.3 GW retiring through September.  

ERCOT leads with 20.1 GW of capacity additions, including 12 GW of solar and 4.5 GW of batteries. CAISO is expected to add 8.9 GW overall, but it beats ERCOT, with 5.1 GW of battery capacity additions. 

Summer is the season with the highest use of natural gas for the sector, with power burn expected to peak in July and August at 47 Bcfd this year. 

“Natural gas used to generate electricity — or power burn — is expected to average 43.5 Bcfd in summer 2024, equal to power burn in summer 2023 but up 9.5% compared to the five-year average,” the report said. 

Coal stockpiles at power plants are higher this year, and coal delivery over the rail network does not face the same issues as the pandemic years from 2020 to 2022, but the Francis Scott Key Bridge collapse in Baltimore has impacted some local coal plants. 

“Coal power plants nearby may experience delays or disruptions to resupply coal stocks via water (barges) if there is protracted disruption to shipping in nearby waterways to clean up the bridge collapse,” the report said. “The bridge collapse temporarily halted coal deliveries by barge to the Brandon Shores and Wagner coal plants, totaling 1,865 MW, which are located directly adjacent to the bridge.” 

Baltimore is the second-largest port for coal exports, shipping the commodity from Appalachia to global markets and representing 28% of exports. That traffic was temporarily delayed because of the bridge collapse. 

The Energy Information Administration is expecting demand to be 2.7% higher this summer than last year and 4.4% over the average of the past five summers. 

“The expected larger electricity consumption this summer results from forecasted warm weather and strong economic growth,” the report said. “Another significant source of electricity consumption growth is the construction of new data centers in many regions of the country.” 

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Is NV Energy Leaning to CAISO’s EDAM?

An NV Energy executive has provided the strongest public indication yet that the Nevada utility is poised to choose CAISO’s Extended Day-Ahead Market (EDAM) over SPP’s Markets+. 

Dave Rubin, federal energy policy director at NV Energy, offered the insight May 22 at a joint session of the CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body.  

A member of the West-Wide Governance Pathways Initiative’s Launch Committee, Rubin spoke during the committee’s presentation on the initiative’s proposal to alter the governance structure of CAISO’s WEIM and — by extension — the EDAM, which will extend the capabilities of the real-time WEIM.  

Step 1 of the Pathways proposal calls for the WEIM’s Governing Body to assume “primary” authority over WEIM/EDAM matters, elevating its power from the “joint” authority it currently shares with the CAISO board over such matters. The move represents the limit of ISO governance changes that can be made under current California law, according to legal analysis performed for the Pathways Initiative. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.)   

Step 2 of the plan seeks to create “a durable governance structure with a fully independent board that has sole authority to determine the market rules for EDAM and WEIM,” which will require changes to California law, something Pathways Initiative backers are pursuing through engagement with the legislature. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)     

In speaking at the May 22 meeting, Rubin said Step 1 “inspires confidence, not only for moving to a form of solid independent authority at some point over the EDAM and EIM in Step 2, but also for the continued engagement of the [Pathways] parties as we expand market services for the benefit of our customers.” 

Rubin said NV Energy has been impressed by the “engagement and encouragement” around Step 1 and the Pathways Initiative by CAISO’s staff and board and the WEIM’s Governing Body that “we believe demonstrate a common understanding of the importance of independent market governance.” 

“It’s certainly one thing to discuss that as a goal, but it’s far more meaningful to take concrete actions to further that objective. And accordingly, for NV Energy, we’ve strongly supported the work of the Launch Committee, and it clearly helps inform our market evaluation,” he said. 

While Rubin’s comments fell well short of an announcement in favor of EDAM, they came during a week when multiple electricity industry sources in the West told RTO Insider that NV Energy officials have been circulating the idea that the utility plans to join the CAISO day-ahead market but probably won’t make an announcement before filing with Nevada regulators. 

The utility did not respond to a request for comment. 

NV Energy in Key Position

An NV Energy decision in favor of EDAM would be pivotal for CAISO and the Pathways Initiative for at least two reasons. 

First, because of its central location in the West, NV Energy’s transmission network has been a key transit point for energy transfers — or wheel-throughs — among balancing authority areas of WEIM participants since it joined the market in 2015. It likely would continue to fulfill that vital function for the EDAM, while also hindering the ability of potential Markets+ participants in the Northwest and Desert Southwest from transacting freely with each other. 

Second, the Pathways proposal stipulates that CAISO’s filing of WEIM primary authority tariff changes with FERC wouldn’t be triggered until EDAM obtains implementation agreements from a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of the CAISO BAA annual load in 2022.  

The EDAM last month secured a full commitment from PacifiCorp and has received tentative — but solid — commitments from Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric. Given that, a utility of NV Energy’s size and location would provide the trigger for CAISO to file the Step 1 change once it emerges from the ISO’s stakeholder process. 

A study published this year by The Brattle Group showed NV Energy could earn as much as $149 million in annual benefits as a member of EDAM versus a top-end benefit of $16 million in Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

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Glick, Christie Clash over States’ Role in FERC Order 1920

VAIL, Colo. — Former FERC Chair Richard Glick faced off against his old colleague, Commissioner Mark Christie, over FERC Order 1920 in the general session of the Western Conference of Public Service Commissioners’ annual summit May 21. 

The order, which directs regional transmission planners to alter their processes to be more forward-looking and proactive, stemmed from a Notice of Proposed Rulemaking issued in 2022 under Glick’s leadership and with Christie’s enthusiastic support because of its consideration of state input. But Christie dissented from the order, which didn’t contain the provisions that had led to him voting for the NOPR. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

“The NOPR gave states a very significant role, particularly in the key functions of the selection criteria for determining what projects go into the regional plan,” Christie said. It also gave states the ability to choose benefits, of which the rule outlines seven, that are key in determining who pays for transmission.  

“The rule actually mandates benefits, which NARUC [the National Association of Regulatory Utility Commissioners], specifically in their comments, said, ‘Don’t mandate benefits; let each region decide what works for them.’ The rule went in the opposite direction,” Christie said. “And of course, the most important issue of all is cost allocation. The NOPR promised that states would consent. … That was critically important to NARUC; it was critically important to every state organization; and it was critically important to me.” 

Order 1920 gives states six months to agree on a cost allocation mechanism with regional transmission planners, who must come up with a default ex ante method. Departing from the NOPR, regional planners are not required to file any agreement with the states or even any state proposals as alternatives.  

“What this rule does is leave states in the position of just being a stakeholder,” Christie said. 

But Glick defended the order and expressed uncertainty about the role of the six-month timeline, which, according to Christie, would be “extraordinarily difficult” for states to reach an agreement in. 

“Heck, I don’t know if six months is too long or too short, but at least there’s an opportunity to get together,” Glick said. “The states have an opportunity in this engagement process to come up with a state agreement cost allocation approach and process.” 

Christie also took issue with elimination of the FERC Order 1000 cost allocation principle 6, which held that transmission providers could have a different allocation process for public policy projects. In Order 1920, all projects are in the same bucket, “which is going to make it extremely difficult in the real-world practical application determining how much of a cost in one of these long-term projects is actually public policy,” Christie said. 

Glick emphasized that the benefits are for the purpose of project selection, not for the purpose of allocating transmission costs. 

‘Massive Wealth Transfer’

Mandating benefits and minimizing state consent over cost allocation will be problematic for the consumers who will bear the burden of transmission costs, argued Vincent Duane, principal at Copper Monarch and former general counsel for PJM. He joined Glick and Christie on the panel. 

“The way this rule is drawing a lot of criticism, and in my opinion rightly so, is that it does potentially represent a massive wealth transfer away from generation developers … and picked up by customers,” Duane said. 

Christie agreed. “This rule is absolutely about a massive transfer of wealth from consumers to developers, no question about it,” he said.  

Glick again pushed back, saying the rule will ensure that costs can only be allocated to customers to the extent they benefit.

“It’s not a wealth transfer,” he said. “The customers are only going to have to pay where they benefit.” 

To ensure protection of consumers, Christie said state regulators should have a more robust role than the order gives them. 

Duane boiled the conversation down to weighing the inevitable compromises that will be made as Western electricity markets expand and utilities and power providers decide which day-ahead market to join.  

“There’s going to be some degree of surrendering of state sovereignty as a result of regionalizing. … There’s going to be some potential that you’re going to be told you’re a beneficiary when you may not feel you’re a beneficiary,” Duane said. “As state policymakers, the question you’re facing is, do the benefits of being a part of a regional organization that plans regionally across multiple jurisdictions — that requires some give and take, and some rough and tumble, and some unscientific, at the end of the day, benefits and costs — is it worth it?”