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November 18, 2024

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DOE CITAP Initiative Aims to Permit New Transmission in 2 Years

The Biden administration on April 25 rolled out a new initiative to cut permitting times for interstate and other major transmission projects to two years and announced up to $331 million in support for a 285-mile line that could bring wind energy from Idaho to Nevada and California. 

Under the new Coordinated Interagency Authorizations and Permits (CITAP) program, the Department of Energy will take the lead on permitting transmission projects and coordinate environmental and permitting processes between federal agencies, Energy Secretary Jennifer Granholm said during an April 24 press briefing. 

DOE’s final rule establishing the CITAP also requires project developers to have comprehensive community participation plans in place before they start the permitting process. 

Granholm called the initiative “a huge improvement from the status quo because developers routinely have to navigate several independent permitting processes throughout the federal government.” 

Granholm also announced that DOE will start negotiating an offtake contract to purchase up to $331 million in electric power capacity from the Southwest Intertie Project-North (SWIP-N), a 285-mile line that will bring wind energy from Idaho to Nevada and California. 

The 2-GW, 500-kV project will provide bidirectional capacity, allowing California and Nevada to send solar and geothermal energy to the Pacific Northwest, according to a DOE fact sheet. The project “will increase grid resilience, especially during wildfires,” Granholm said. 

Both announcements reflect DOE’s “holistic, multifaceted approach to grid improvements and to grid expansions,” both of which will be needed to reach a new administration goal of upgrading 100,000 miles of U.S. transmission lines over the next five years, she said during the press briefing. 

CITAP

The effort to streamline and speed up transmission permitting began in May 2023, when DOE and eight other federal agencies and councils signed a memorandum of understanding expediting what had become a tortuous process for transmission developers ― and a major bottleneck for interconnecting wind and solar projects to the grid. 

Granholm pegged the average permitting time for transmission projects at four years, with some projects taking more than a decade. The poster project for ridiculously long permitting times, Pattern Energy’s SunZia transmission line, now under construction, took 17 years to permit. (See SunZia Project Wins Final Approval, Signs Offtakers.) 

CITAP’s two-year limit on permitting is also in line with the Fiscal Responsibility Act, passed in June 2023, which mandated a two-year cap for environmental reviews required for any energy project on federal land under the National Environmental Policy Act (NEPA). 

The CITAP program is targeted at “regionally or nationally significant transmission lines” of 230 kV or higher that cross state lines and are expected to require an environmental impact statement, according to DOE. Projects may also be eligible if they are approved by the director of DOE’s Grid Deployment Office, are entirely located in ERCOT or are seeking a construction permit from FERC under specific provisions of the Federal Power Act. 

One of the main features of the new program is “an interagency preapplication process to ensure that developer submissions for federal authorizations are ready for review on binding two-year timelines without compromising critical [NEPA] requirements,” according to a DOE press release. The goal is for developers to collect all documentation needed for federal permitting before submitting applications. 

The development of a community participation plan for each CITAP project as part of the preapplication process is intended to ensure “meaningful engagement with tribes, states, local communities and other stakeholders,” according to DOE. 

The department will coordinate with all relevant federal agencies to produce a single NEPA review to reduce duplication of efforts. The CITAP program will be open to state permitting authorities, which will be able to use final NEPA reviews in their own decision-making processes. 

However, CITAP will not affect state permitting authorities, according to a senior administration official speaking on background. 

Coordination between agencies and developers will be handled via an online portal, where developers will be able to upload required documentation and other information. Federal agencies will then be able to review those submissions and provide feedback if changes or further information is needed. 

“If you’re a grid wonk, CITAP is the coolest thing since sliced bread,” National Climate Advisor Ali Zaidi said during the press briefing. “What Secretary Granholm has done here is a very path-breaking and inventive approach to getting the grid built out at the speed and scale we need.” 

Southwest Intertie

SWIP-N will be the fourth project DOE has supported through its Transmission Facilitation Program (TFP), launched in October 2023.  

At the time, DOE announced it would be investing $1.5 billion in federal funds to become an anchor off-taker for three interstate transmission projects that together could add 3.5 GW of capacity to the grid. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

Authorized in the Infrastructure Investment and Jobs Act, the TFP has a revolving fund of $2.5 billion to “help overcome the financial hurdles associated with building new, large-scale transmission lines and upgrading existing transmission lines,” DOE said. Having the department as an anchor off-taker may both increase investor confidence and encourage other customers to purchase capacity from the project. 

Developed by Great Basin Transmission, a subsidiary of LS Power, SWIP-N could add 2 GW of capacity to the Western grid. According to DOE’s National Transmission Needs Study, an additional 3.3 GW of transfer capacity will be needed between the Mountain and Northwest regions by 2035; SWIP-N could cover 58% of that total, the department said. 

SWIP-N is the final, northern section of a larger project including both the 60-mile Desert Link line and the 231-mile One Nevada project, both of which are in operation. Construction on SWIP-N will also include an upgrade for a key Nevada substation that could add another gigawatt of capacity on the One Nevada line. 

Having DOE as an off-taker for SWIP-N could provide “an anchor that will allow us to move forward more quickly with procurement activities and securing slots for long-lead equipment, thereby proceeding to construction and placing the project in service faster than otherwise possible,” said Paul Thessen, president of LS Power Development. 

The company anticipates beginning construction on the project in 2025 and bringing it online in 2027. 

Categorical Exclusions

In another move to streamline project permitting, DOE announced an additional final rule April 25 updating its guidelines for issuing “categorical exclusions” for environmental reviews of certain categories of clean energy projects. 

A categorical exclusion is granted when DOE determines that a category or specific kind of project or action will have no significant environmental impact. Expanding the kinds of projects that qualify for exclusions will “reduce the cost and time for environmental analysis incurred by DOE, project developers and the public,” according to the announcement press release. 

In a major push for the updating of transmission lines, DOE widened the categorical exclusion for such projects by lifting the existing 20-mile cap on the length of a transmission line upgrade that can qualify for an exclusion. The new rule also allows exclusions for transmission upgrades involving a relocation within an existing right-of-way or within previously disturbed or developed land. 

The rule specifically refers to reconductoring projects ― installing advanced conductors to expand line capacity ― as a kind of grid upgrade that could be given categorical exclusions. 

For energy storage systems, the new rule allows for categorical exclusions for the construction, operation, upgrade or decommissioning of battery or flywheel storage systems located either within or adjacent to a previously disturbed or developed area. 

DOE issued a categorical exclusion for solar photovoltaic projects on previously disturbed or developed land in 2011, limiting the exclusion to projects of 10 acres or less. This rule has been updated to remove the cap on project size.  

The department noted it was basing the changes on its “years of experience evaluating the environmental impacts of these types of projects” but will “continue to look closely at each proposed project while being able to complete its environmental review in a faster and less expensive manner.” 

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FERC Proposes Adopting NAESB’s Latest Revisions

FERC this week proposed ordering utilities to adopt the latest version of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communication Protocols for Public Utilities, soliciting feedback on the plan from stakeholders (RM05-5). 

In its Notice of Proposed Rulemaking, the commission said adopting version 004 of the NAESB standards “would enhance the electric industries’ systems and software security measures and improve efficiencies of certain business processes transactions.” Stakeholders have until 60 days after the NOPR’s publication in the Federal Register to submit their comments. 

NAESB published version 004 on July 31, 2023, after their development by the organization’s Wholesale Electric Quadrant (WEQ), filing them with FERC the same day. Version 004 contains a mix of newly created standards and modifications to existing standards, building on version 003.3, which FERC adopted in 2021. (See NAESB Standards Gain Final FERC Approval.) 

Standards to be modified in version 004 are: 

    • WEQ-000: Abbreviations, acronyms and definition of terms 
    • WEQ-001: Open access same-time information system (OASIS) 
    • WEQ-002: OASIS Standards and Communication Protocol (S&CP) 
    • WEQ-003: OASIS data dictionary 
    • WEQ-004: Coordinate interchange 
    • WEQ-005: Area control error equation special cases 
    • WEQ-006: Manual time error correction 
    • WEQ-008: Transmission loading relief (TLR) – Eastern Interconnection 
    • WEQ-010: Contracts related business practice standards 
    • WEQ-012: Public Key Infrastructure (PKI) 
    • WEQ-013: OASIS implementation guide 
    • WEQ-015: Measurement and verification of wholesale electricity demand response 
    • WEQ-021: Measurement and verification of energy efficiency products 
    • WEQ-022: Electric industry registry 
    • WEQ-023: Modeling 

FERC’s NOPR proposed not to incorporate WEQ-010, a move the commission said is “consistent with our past practice of not incorporating … any optional model contracts and related documents because we do not require the use of these contracts.” 

In addition, FERC said it plans not to include one of the two new sets of standards in the latest version. WEQ-025 (Grid services supporting wholesale electric interactions) aims “to promote greater consistency in wholesale market interactions and communication exchanges by … resources such as distributed energy resources and batteries.” A recommendation from the Department of Energy inspired these standards, joined by Lawrence Berkeley National Laboratory and Pacific Northwest National Laboratory. 

The WEQ-025 standards group operations-based grid services currently used in wholesale markets into six categories: energy grid service, reserve grid service, regulation grid service, frequency response grid service, voltage management grid service and black start grid service. They also lay out which attributes system operators may use to define requirements for services within their wholesale electricity markets, establishing a technology-neutral framework to account for the varying names for similar grid services in various markets. 

FERC said it recognizes the motivation for the grid services standards but said WEQ-025 could create confusion because of the use of terms that are similar to those used in FERC’s pro forma Open Access Transmission Tariff. 

The other new standard family, WEQ-024 — which is proposed for adoption — “reorganizes existing NAESB cybersecurity business practice standards” in response to a recommendation from DOE and Sandia National Laboratories. FERC said the consolidation should make it easier for NAESB and the commission to revise cybersecurity standards “to help match the fast pace of changes in cybersecurity practices.” 

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FERC, NERC Review January Winter Storm Performance

The North American electric and natural gas systems survived this year’s Arctic storms with no major incidents, demonstrating significant progress from the performance issues in previous severe winter events, FERC and NERC staff said at the commission’s open meeting this week. 

However, the presenters said there still is considerable room for improvement and both industries continue to face challenges from extreme cold weather and the impacts of climate change. 

The winter storms, also known as Gerri and Heather, began on Jan. 10, according to Chanel Chasanov from FERC’s Office of the General Counsel. Gerri entered the picture first, moving through the Pacific Northwest, across the Rocky Mountains and into the Midwest, and then up through the Great Lakes region and into southern Canada on Jan. 13. That same day, Heather developed, also beginning in the Pacific Northwest but taking “a more southern route” through Texas, Oklahoma and Tennessee before sweeping into the Mid-Atlantic and ending in Canada on Jan. 17.  

Both Gerri and Heather brought “frigid cold, high winds, heavy snow and in some places freezing precipitation,” Chasanov said. But while the cold weather caused some challenges to gas and electric reliability, there was no operator-initiated load shed and generators reported fewer derates and outages than in other recent cold weather events such as winter storm Uri in 2021 and 2022’s Winter Storm Elliott. 

FERC, NERC and the regional entities launched a review in February of the electric grid and natural gas system’s performance during Gerri and Heather in order to determine the progress made since the “unacceptable” performance during Elliott. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) Chasanov said that because there were no major incidents to focus on, the team chose “a more qualitative approach” informed mainly by voluntary interviews with grid operators and staff presentations than the quantitative approach favored in previous years. 

The report found that conditions during the storms generally were less severe than those seen in Uri and Elliott, which contributed to the system’s performance. For example, entities encountered less freezing precipitation than in the previous incidents and did not see wind turbine blades ice up to the extent they did in Elliott.  

However, presenters noted that the hardest-hit area in January was the Pacific Northwest, where Chasanov said winters typically are mild and utilities “had limited operational experience in dealing with these … conditions” compared to their counterparts in the Eastern Interconnection. Entities in this region reported the temperatures of Gerri and Heather represented a “one-in-30-years cold event,” with record lows experienced in parts of Oregon and Washington. 

Matt Lewis, NERC’s manager of event analysis, said “neighboring reliability coordinators and balancing authorities worked closely” on their winter response measures before and during the storms, holding daily conference calls beginning seven days before the onset of severe weather. 

“These entities noted that this practice provided a higher level of situational awareness than they experienced during Uri and Elliott and improved their ability to make more informed reliability decisions,” Lewis said. “Additionally, based on lessons learned, one grid operator’s executive team met daily during Gerri and Heather to communicate operating plans … from staff [in] generation and transmission operations to the control center in natural gas scheduling.” 

Robert Clark from FERC’s Office of Electric Reliability said the performance of the natural gas system “validates the important recommendations and lessons learned from” the reports on Uri and Elliott, as well as the joint report on black-start resource availability released last December. (See FERC Black Start Report Pushes Gas-electric Coordination.)  

While the storms “triggered a rise in natural gas demand, coupled with a nearly simultaneous plummet in … production” as seen in previous events, Clark said gas entities proactively reached out to the public to communicate current operating conditions and appeal for conservation. Utilities also worked to prevent outages by increasing pipeline pressures ahead of time to ensure the presence of gas where needed, including for electric generation. 

“The natural gas system experienced fewer disruptions during Gerri and Heather as compared to Uri and Elliott,” but the experience of January “demonstrated the benefit of advanced preparations, diversity of natural gas supplies, [and] natural gas storage and reinforce the need to continue implementing the recommendations from” previous reports, Clark said. 

FERC Chair Willie Phillips thanked the presenters, joking that the positive news allowed him to wear his “happy face,” rather than the “determined face” he used for previous winter storm reports. He emphasized that winter preparedness “remains a priority” for the commission and called for stakeholders to continue implementing the recommendations issued after Uri and Elliott, while reiterating his support for an organization to ensure reliability in the natural gas industry. 

In a statement, NERC CEO Jim Robb said the report indicated “the industry prepared and got ready for the Arctic cold” ahead of January’s storms. 

“I am confident that the winter reliability requirements in [NERC’s] cold weather standards are providing clarity and the winter preparation support NERC and the regional entities are providing is making a difference in generation performance during cold weather events, but as the chairman notes, there is still much left to do,” Robb added. 

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EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt

Coal-fired power plants nationwide will either have to close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032 under EPA’s long-awaited final rule issued April 24. 

The 1,020-page document actually contains four different, “severable” rules: 

    • the repeal of the Affordable Clean Energy rule that the agency issued during the Trump administration; 
    • greenhouse gas emission guidelines for existing coal plants; 
    • new source performance standards for gas-fired plants built after May 23, 2023; and 
    • revisions to the performance standards for coal plants that undergo a large modification, matching the new emission guidelines. 

Absent from the package are emissions guidelines for existing natural gas plants, as EPA proposed in May 2023. (See EPA Proposes New Emission Standards for Power Plants.) The agency first announced the change to its proposal in February. (See EPA to Strengthen Emissions Regs for Gas Power Plants.) 

During a press conference April 24, EPA Administrator Michael Regan said those guidelines have been delayed because of feedback from both industry and environmental groups, which pushed the agency to “do better.” 

The agency has opened a docket and issued “framing questions to gather input about a more comprehensive approach to reduce greenhouse gases of existing gas combustion turbines in the power sector,” Regan said. “We are committed to expeditiously proposing GHG emission guidelines for those units … and we’re going to do it in a very transparent and engaging way.” 

An EPA analysis estimates the rule could cut 1.3 billion metric tons of power-sector carbon dioxide emissions by 2047 and provide climate and health benefits totaling $370 billion, or about $20 billion per year. 

“In 2035 alone, that means preventing 1,200 premature deaths, 870 hospital visits, 360,000 avoided cases of asthma symptoms, 48,000 avoided school absences and 57,000 lost workdays,” Regan said April 25 at a public announcement of the rules at Howard University in D.C. 

Anticipating pushback from the electric power sector and fossil fuel organizations, Regan said the CO2 rule will not only protect public health but also allow the power sector to “confidently prepare for the future by enabling strategic long-term investment and establishing an informed, multiyear planning strategy.” 

“Despite what you will hear and what they will say, we can do it all while ensuring the power sector can provide affordable, reliable electricity for the long term,” he said. 

In addition to the CO2 rule, EPA issued pollution-reduction standards for wastewater and coal ash produced by power plants and updated the Mercury and Air Toxics Standards. 

“Each of these rules contains transparency requirements, so that the emissions, the discharges and the compliance data are made available to the public, ensuring that power plants are held responsible and accountable for their activities,” Regan said. 

“The U.S. is closing in on its goal to cut greenhouse gas emissions in half by 2030,” the Natural Resources Defense Council posted on X. “Now, the EPA needs to finish the job and limit emissions from already built gas power plants that continue to threaten communities and our planet.” 

Altered Deadlines

The final rules push up some compliance deadlines and extend others compared to last year’s proposal.  

For example, the deadline for coal plant closure or CCS abatement was 2040 in the proposed rule, and new baseload natural gas plants originally had until 2035 to reduce emissions by the 90% requirement, as opposed to 2032 in the final rule. 

The rule also provides different compliance levels for existing coal plants depending on whether they intend to operate past Jan. 1, 2039: 

    • Plants intending to operate past 2039 will have until Jan. 1, 2032, to cut their emissions to a level based on a presumption that they will install a CCS system capable of capturing 90% of their emissions.  
    • The emission cuts for plants planning to close by Jan. 1, 2039, will be based on a presumption that they will shift their fuel mix to 40% natural gas by Jan. 1, 2030. 
    • Plants with a demonstrable commitment to shutting down before Jan. 1, 2032, will be exempt from the rule. 

States will also be able to issue “variances” for individual plants that have “fundamentally different circumstances than those considered by EPA and … cannot reasonably achieve [the] required degree of emission limitation,” according to an agency summary. 

The standards for new natural gas plants also vary based on a plant’s expected operation level: 

    • Baseload plants intending to generate at least 40% of their maximum annual capacity will have to comply with two standards: a first phase based on efficient design and operation, and a second phase assuming 90% carbon capture by Jan. 1, 2032. 
    • Intermediate-load plants planning to operate at 20 to 40% of their maximum capacity will only have to comply with the efficient design and operation standards. 
    • Plants expecting to operate at less than 20% of their maximum capacity — mostly peaker plants — will have to comply with a standard that assumes their use of low-emitting fuels. 

The different levels for coal and natural gas are intended to reflect “the fact that the longer-running and more heavily utilized a power plant is, the more cost-effective it will be to install controls for CO2 emissions.” 

States will be required to submit their plans for complying with the final rule within two years of its publication in the Federal Register. Regan said the rule allows for flexibility in state plans, for example, allowing coal and new natural gas plants to exceed the EPA limits if needed to provide short-term emergency power, for example, during an extreme weather event. 

State plans can also allow for longer-term flexibility if a coal plant scheduled to shut down is kept in operation to ensure utilities or transmission operators can supply regional reliability. States may also seek one-year extensions to comply with specific standards because of “unexpected delays with control technology implementation that are outside the owner or operator’s control,” according to the summary. 

The CCS Issue

The rule acknowledges concerns raised by environmental justice and community groups about EPA’s promotion of CCS as a best system of emissions reduction (BSER) under Section 111 of the Clean Air Act.  

While still an emerging technology, CCS has received a range of federal support, with the Department of Energy funding several demonstration projects. These projects also may receive generous tax credits from the Inflation Reduction Act. 

EPA argued its carbon pollution standards are “performance standards and do not require the installation or operation of any particular technology. Individual owners and operators will decide how best to meet the requirements laid out in the rule. … 

“EPA is committed to implementing its programs and working with federal partners to ensure that where CCS is deployed, it is implemented in a way that considers community input and is protective of public health, safety and the environment.” 

Many of the criticisms lobbed in response to the final rules focused on CCS. 

“The path outlined by the EPA today is unlawful, unrealistic and unachievable,” Jim Matheson, CEO of the National Rural Electric Cooperative Association, said in a statement. “The rule mandates the widespread adoption of technology that is promising but not ready for prime time.” 

“CCS is not yet ready for full-scale, economywide deployment, nor is there sufficient time to permit, finance and build the CCS infrastructure needed for compliance by 2032,” said Dan Brouillette, CEO of the Edison Electric Institute. 

The Electric Power Supply Association said the package “relies on unavailable technology and will stymie much needed investment in new, more efficient and cleaner power resources as older units retire.” 

“While EPSA welcomed the EPA’s announcement that it had removed existing gas plants from its proposed emissions regulations, the final rule released today is still a painful example of aspirational policy outpacing physical and operational realities,” CEO Todd Snitchler said. 

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Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day

[EDITOR’S NOTE: This story was updated on April 26, 2024, to include comments made by MISO officials and stakeholders during a teleconference.]

MISO said its second seasonal capacity auction returned sufficient capacity in all zones except a portion of Missouri, where prices soared to more than $700/MW-day in fall and spring.  

Save for Missouri’s Zone 5, all local resource zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. MISO published results at the close of business April 25. 

Zone 5 — which contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department — cleared at the $719.81/MW-day cost of new entry (CONE) for generation in the spring and fall, then followed other zones in clearing at $30/MW-day in the summer and $0.75/MW-day in the spring.  

MISO said its auction showed Zone 5 didn’t have enough capacity to meet its local clearing requirements in the shoulder seasons and that large coal retirements played a factor in the capacity deficiency. CONE, the equivalent value of building new generation, is the maximum price MISO’s tariff will allow the auction to clear.  

MISO said while the auction indicates it will meet most of its 2024/25 planning year resource adequacy requirements, “pressure persists with reduced capacity surplus across the region and a shortfall in Zone 5.” MISO’s planning year begins June 1 with the summer season.  

“Once again, our seasonal construct worked as designed by identifying the highest risk periods on the system,” MISO President and COO Clair Moeller said in a press release. “These results continue to provide real-world examples of the urgent and complex challenges to the electric grid in the MISO region.” 

The grid operator said year-over-year, capacity surpluses in MISO receded by 30% in summer, especially in MISO Midwest. The opposite was true in winter, where all zones are due to experience higher surpluses than last winter.  

This fall, Zone 5 is set to experience an 872-MW shortfall; in 2023, it experienced a 2.4-GW surplus. Zone 5’s local clearing requirement for fall rose by more than 2 GW year over year.   

Overall, MISO said it experienced a 4.6-GW capacity surplus this year, down from last year’s nearly 6.5-GW surplus.  

Last year, MISO zones cleared mostly at $2/MW-day in winter, $10/MW-day in summer and spring, and $15/MW-day in fall. Zone 9 in Louisiana and southeast Texas was an outlier and cleared at $59.21/MW-day in fall and $18.88/MW-day in winter due to price separation to meet requirements. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.) 

MISO was required to meet a total 135.7-GW summer planning reserve margin requirement. Its 9% summer 2024 planning reserve margin is higher than the 7.4% annual planning reserve margin used in last year’s Planning Resource Auction (PRA). (See MISO Crunching Data for 2nd Seasonal Capacity Auction.)  

“Retirements, reduced imports and higher requirements are insufficiently offset by new capacity,” MISO reported, adding a warning that its withering surplus, paired with the ongoing clean energy transition and new load demands, will continue to strain resource adequacy. 

MISO said only load-serving entities that entered its PRA without enough capacity to meet their resource adequacy requirements are exposed to auction clearing prices. The RTO said the auction’s impacts on consumer costs “will depend upon the shortfall amount and other factors, such as wholesale purchase agreements or retail rate arrangements with state regulators.” 

“This year’s results amplify the need and urgency for MISO’s efforts around resource availability and market redefinition,” Moeller said. “We will continue working with our member utilities and states to hone regional planning processes and market mechanisms to meet the needs of our evolving fleet.” 

MISO said its proposals before FERC to install a sloped demand curve in the auction and to accredit capacity based on generators’ expected availability, alongside its ongoing work to stimulate critical generating attributes, should help states ensure resource adequacy. 

MISO’s Independent Market Monitor has reviewed the offers and results of the 2024 PRA and has certified the results. 

A ‘New Risk Paradigm’

During an April 26 teleconference to discuss auction results, Senior Director of Resource Adequacy Durgesh Manjure said the auction results show MISO is entering “a new risk paradigm.”

Manjure said the planned closure of a coal plant by fall affected Zone 5’s capacity supply, seemingly referencing Ameren Missouri’s Rush Island, which is slated close by mid-October per a court order for years of illegal air pollution. (See Court: Ameren Still Without Remedy for Years of Rush Island Air Pollution.)

He said Missouri’s capacity picture also is “aggravated” by planned generation maintenance outages in the zone during fall.

“We do believe we’re at the front end or early stages of this evolving risk,” Manjure said, calling the reliability dangers “embryonic.” He said the “unsurprising” effects of generation retirements, increasing planning reserve margins and shrinking imports will continue to intensify.

“And all of this was insufficiently offset by new capacity,” Manjure said of the 2024/25 results.

“We believe the changes we see this year in results are very important. These results signal the need for continued due diligence in our region,” Director of Resource Planning Scott Wright said, referencing the reduction in the Midwest region’s capacity surplus.

Sustainable FERC Project’s Natalie McIntire asked if generation owners in Zone 5 can shift planned maintenance outages to free up generation in the fall.

“It’s really up to the asset owner … and frankly, after-the-fact changes, we haven’t dealt with those before. We’ll have to see,” Majure said.

He added that the auction results are “only a piece of the puzzle” and that MISO has been in a shortage situation before for its entire Midwest region in the 2022/23 planning year. In that case, MISO didn’t experience a loss-of-load scenario, he said. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Manjure said Zone 5’s shortage doesn’t “immediately” mean shortfalls in the fall and spring, pointing out that imports and non-firm energy can assuage the situation.

This is the second year MISO has separated its capacity auction by season. FERC in 2022 gave the RTO the go-ahead to establish four seasonal capacity auctions with separate reserve margins. (See FERC OKs MISO Seasonal Auction, Accreditation.)

MISO will discuss the auction results again at its May 22 Resource Adequacy Subcommittee meeting.

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NEPOOL Transmission Committee Briefs: April 25, 2024

The NEPOOL Transmission Committee has voted to approve updates to ISO-NE’s Order 2023 compliance proposal to account for Order 2023-A.  

Order 2023-A, issued in late March, made some minor changes to the original order in response to rehearing requests and extended the compliance deadline. (See FERC Upholds, Clarifies Generator Interconnection Rule.) 

“None of these changes appear to materially impact the New England Order No. 2023 compliance proposal,” ISO-NE wrote in a memo responding to the order. “The revisions, however, will need to be taken into account in the compliance proposal and the incremental changes to it will need additional NEPOOL votes.” 

ISO-NE now plans to submit two filings to FERC on May 14: its Section 206 compliance proposal and a Section 205 filing that would align the procedures for small generators and elective transmission upgrades with the new cluster process. 

“While this filing is an integrated proposal, its components are independent to allow for the commission to direct changes,” said Al McBride of ISO-NE. 

The updates would push back the timeline for ISO-NE’s initial “transitional cluster study.” The RTO now proposes an “eligibility date” of June 13, which would be the due date for interconnection customers to have a valid interconnection request (IR) to be eligible for the transitional cluster.  

“The ISO will not accept IRs submitted after the eligibility date until the first cluster entry window opens in 2025,” McBride said. 

ISO-NE now plans to proceed with late-stage system impact studies until Aug. 30, with the aim of limiting the number of projects that need to enter the transitional cluster study. If these studies are not complete by this Aug. 30 deadline, the projects still could enter the transitional cluster. 

The timeline for the capacity network resource (CNR) group study, which is aligned with the schedule of the 2024 interim reconfiguration auction qualification process, will not be moved forward. This interim process would allow new resources that complete their system impact studies by June 30 to qualify for reconfiguration auctions through the 2027-28 capacity commitment period. 

“Aside from the transitional CNR group study, the timeline for the remaining Order No. 2023 transition items has been updated to account for the delay caused by Order No. 2023-A,” McBride said.  

The updated proposal passed April 25 with no objections and now heads to the Participants Committee for a vote on May 2.  

DASI Conforming Changes

Dennis Cakert of ISO-NE outlined ISO-NE’s proposal to change the tariff definition of “self-schedule” to conform with its day-ahead ancillary services initiative (DASI). 

“The ISO proposes to modify the definition of “self-schedule” to state that self-scheduled (SS) external transaction (ET) purchases (imports) are priced at the offer floor and SS ET sales (exports) are priced at the external transaction cap in the [day-ahead market],” Cakert noted. 

The Transmission Committee will vote on the proposed changes May 16.  

FERC Denies Waiver Request

Also on April 25, FERC denied a waiver request by Moscow Development Co. (MDC) related to a missed deadline to withdraw an interconnection request to receive a partial refund on its $50,000 initial deposit (ER24-1295). 

MDC argued it received incomplete information at the scoping meeting, causing it to miss the deadline. The company requested a waiver to let ISO-NE return the unapplied part of its deposit. 

ISO-NE supported the request, noting that “without the waiver, the ISO cannot return the unused portion (approximately $48,000) of the deposit to MDC.” 

However, despite ISO-NE’s support, FERC denied the request “on the basis that it is prohibited by the filed rate doctrine.” The filed rate doctrine prohibits the commission from making changes to previously filed and approved rates. 

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CAISO Receives FERC Approval to Increase Soft Offer Cap

FERC has approved CAISO’s request to increase its capacity procurement mechanism (CPM) soft offer cap from $6.31/kW-month to $7.34, which CAISO states would better reflect inflation, labor rights and higher bilateral capacity prices (ER24-1225).The increase also would better position the ISO to maintain reliable grid operations in the summer, the order reads. 

The soft offer cap, referenced when load-serving entities bid offers into the market to resolve resource adequacy deficiencies, is based on fixed operation and maintenance costs, ad valorem taxes and insurance costs of a reference unit, plus a 20% adder. 

According to its tariff, CAISO is required every four years to conduct a stakeholder process and evaluate whether to update the CPM soft offer cap. In May 2023, the California Energy Commission provided CAISO with a study demonstrating CAISO’s soft offer cap doesn’t adequately reflect fixed costs and should be increased to $7.34/kW-month.  

“CAISO contends that the proposed soft offer cap is also high enough to ensure contributions to fixed cost recovery and low enough to provide appropriate market power mitigation,” the April 25 FERC order states. “CAISO adds that the proposed soft offer cap will create greater incentives for resources to accept voluntary CPM designations.” 

Motions to intervene were filed by consumer advocacy organization Public Citizen, Calpine, Pacific Gas and Electric, the California Department of Water Resources’ State Water Project, the city of Santa Clara and the Northern California Power Agency. CAISO’s Department of Market Monitoring filed comments supporting the tariff provision. 

“DMM supports the proposed tariff revision to better position the CAISO to maintain reliable grid operations and increase incentives for resources to accept voluntary CPM designations,” DMM’s letter to FERC reads. “In addition, accepting the amendments will allow for the CAISO and its stakeholders to focus on a more comprehensive set of changes needed in the overall CPM and resource adequacy framework.” 

CAISO plans to implement the changes by early June. 

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Wildfire Litigation Poses Threat to Xcel Energy

Xcel Energy said it expects to incur a financial loss from Texas wildfires that could have a “material adverse effect” on the company’s bottom line. 

The Minneapolis-based company has acknowledged distribution poles belonging to its Southwest Public Service Co. subsidiary sparked the February Smokehouse Creek fire in the Texas Panhandle north of Amarillo. The fire, the largest in state history, consumed more than 1 million acres before being contained. 

“I’ve been to the Panhandle, and I’ve witnessed the impacted areas,” Xcel CEO Bob Frenzel told financial analysts April 25 during the company’s first-quarter earnings call. “I can speak for the entire Xcel Energy team when I say that we are saddened by the losses and we will stand with the Panhandle community as we recover, rebuild and renew that area as we have for over 100 years.” 

Xcel has disputed claims that it acted negligently in maintaining and operating its infrastructure. It faces 15 lawsuits from the fire and is processing the 46 loss claims it has received. The company recorded a pretax charge of $215 million to cover losses before insurance. 

But if the company is liable and must pay damages, the amount could exceed insurance coverage of roughly $500 million for 2024 wildfire losses and “could have a material adverse effect on our financial condition, results of operations or cash flows.”  

The Texas House of Representatives created an investigative committee on the wildfires and has held several public hearings. It plans to issue a report in early May. 

Frenzel said the $215 million loss is a preliminary estimate that reflects the low end of a range and is subject to change. He said Xcel is responding to the wildfire risk by accelerating pole inspections and cutting power to lines during dangerous weather, among other measures. 

“Like all utilities, we are experiencing profound changes in weather- and climate-related impacts on our operations,” Frenzel said. “As a result, we must continue to evolve our operations for these unparalleled dynamics.” 

Xcel reported earnings of $488 million ($0.88/share) for the first quarter, compared with $418 million ($0.76/share) in the same period last year. The company said the results reflected increased infrastructure investment recovery and lower operations and maintenance expenses, partially offset by increased interest charges and depreciation. 

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Entergy Earnings Call Focuses on La. Resilience Plan, Nuclear Outage and Settlements

Entergy’s CEO touched on several recent developments on a first-quarter earnings call April 24, including the utility’s recently approved grid-hardening plan for Louisiana, an outage at the Waterford 3 nuclear plant and New Orleans’ acceptance of a settlement concerning Grand Gulf nuclear station.  

Entergy CEO Drew Marsh said Entergy over the quarter made strides in “risk reduction efforts that will benefit our key stakeholders” during the call.  

Entergy reported first-quarter earnings of $230 million ($1.08/share) compared to first-quarter 2023 earnings of $311 million ($1.47/share).  

Entergy CFO Kimberly Fontan said the lower-than-expected earnings can be attributed to mild weather, planned generator maintenance outages and lower sales to cogeneration customers, among other factors.  

Marsh framed the Louisiana Public Service Commission’s April 19 approval of the utility’s $2 billion grid-hardening plan in the state as a positive development.  

“A more resilient grid will also serve as a catalyst for growth as it bolsters confidence for customers seeking to locate or expand in our service area,” he said.  

The PSC approved Entergy Louisiana’s plan just four days after the utility submitted it; consumer advocate groups blasted the process as rushed and only in Entergy’s interest. (See Louisiana PSC Adopts Nearly $2B Entergy Resilience Plan.)  

Marsh said the plan includes 2,100 transmission and distribution projects that will be crucial to communities, and Entergy Louisiana plans to start work immediately. 

Marsh noted Entergy Louisiana also filed for PSC approval of its Bayou Power Station, a $411 million, 112-MW “quick-start, nonbaseload” natural gas power station. He called it an “innovative solution to meet the power needs in a challenging area on the edge of the Eastern Interconnect.” 

The power plant is planned to sit atop a barge in a southern Louisiana canal and could rise with storm surges.  

Marsh drew attention to the New Orleans City Council on April 18 agreeing to a $252 million settlement to resolve its longstanding allegations of mismanagement and poor performance at the Grand Gulf nuclear station in in Port Gibson, Miss. 

The city council settled with Grand Gulf operator and Entergy subsidiary System Energy Resources, Inc. on three fronts: $116 million to resolve allegations around SERI’s mismanagement; $138 million to settle allegations of dubious tax accounting; and $500,000 to lay concerns over reliability to rest. 

“This agreement is consistent with SERI settlements with Mississippi and Arkansas, both of which were approved by FERC and determined to be fair and reasonable. … With the addition of New Orleans, SERI has resolved roughly 85% of its litigation risk,” Marsh said.  

Rod West, president of Entergy utility operations, said Entergy has a shot at pursuing a settlement with Louisiana “in the near term” over Grand Gulf operations now that New Orleans’ litigation is over.  

The Louisiana PSC has been a holdout on a settlement, maintaining ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers. (See Former Employee Details Failures at Entergy’s Grand Gulf.)  

Marsh also delivered an update on the offline Waterford 3 nuclear generating station in St. Charles Parish. He said the plant is “working to recover” from a shutdown following a transformer failure. He said the failed transformer was 20 years old, halfway through its expected lifespan.  

“Early indications point to equipment failure as the cause,” Marsh told shareholders.  

In the meantime, Entergy plans to outfit Waterford 3 with an interim, spare transformer to bring the plant to 90% capacity over the summer until a fully compatible replacement transformer arrives, Marsh said.  

“We’re working diligently to bring the plant back online in the coming weeks,” he said.  

Finally, Marsh said Entergy utilities will submit by the end of May six projects furthering the clean energy transition for funding consideration from the U.S. Department of Energy’s Grid Resilience and Innovation Partnership program. Entergy received letters of encouragement on six of the eight preliminary proposals it submitted late last year. Marsh said federal support stands to lower customers’ capital costs. (See Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings.)  

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Prices, Load Down in MISO March Operations

MISO energy prices plunged on record-low natural gas prices in March while the RTO managed a comparatively lower, 68-GW average systemwide load.  

March average load was lower than MISO’s 71-GW averages in 2022 and 2023, MISO reported.  

The footprint peaked for the month at 84 GW on March 19, lower than March 2023’s 89-GW peak and in line with previous March peaks in 2021 and 2022.  

Real-time locational marginal prices were about $20/MWh for the month as the footprint experienced $1/MMBtu natural gas and $2/MMBtu coal prices. Real-time prices were lower than March 2023’s $26/MWh and less than half of 2022’s $42/MWh.  

MISO’s average 48 TWh of supply came from a mix of 19 TWh of natural gas, 11 TWh of wind, 10 TWh of coal and 7 TWh of nuclear generation. The system again set an all-time solar generation record March 23 when arrays supplied 5.3 GW, or 6% of load at the time. MISO solar generation peaks have become commonplace as more solar projects clear the interconnection queue.  

The RTO averaged 49 GW of daily generation outages over March, more than March 2023’s 45-GW average.