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November 7, 2024

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FERC Rejects Rehearing Request for Mystic Agreement Disclosures

FERC has rejected a rehearing request from a group of New England public power utilities seeking the disclosure of additional information related to the Mystic cost-of-service agreement between Constellation and ISO-NE (ER18-1639-026). 

In October, FERC initially ruled against the public power groups’ request for additional disclosures of information, focused on the agreement’s supply arrangement with the nearby Everett LNG import facility. (See FERC Rules Against Additional Mystic Agreement Disclosures.)  

The public power organizations argued in their November rehearing request that FERC improperly denied outside entities the ability to review and challenge data related to the Mystic Generating Station’s revenues and the management of Everett as a part of the Mystic agreement. Both Everett and Mystic are owned by Constellation. 

The coalition wrote that FERC’s denial of the request for more transparency “pulls an impenetrable veil over information that the ISO-NE customers … require in order to verify the justness and reasonableness of the charges imposed on them and their customers.” 

In its Feb. 15 response to the rehearing request, FERC stood by its decision to deny additional public disclosures.  

“We continue to find the Mystic Agreement’s arrangement is just and reasonable and appropriately provides sufficient assurance that the inputs to the Mystic Agreement filed rate are accurate,” FERC wrote. 

The commission emphasized its prior finding that ISO-NE’s auditing rights in the agreement “are sufficient to ensure accuracy and transparency while preserving the confidentiality of commercially sensitive information and avoiding security risk.” 

ISO-NE and Constellation signed the Mystic agreement in 2018 over concerns that Mystic’s impending retirement would introduce significant resource adequacy risks to the regions. The cost-of-service agreement to retain Mystic began in June 2022 and will expire at the end of May 2024. 

As Mystic is the main customer of LNG from Everett, its looming retirement has triggered an ongoing effort to retain Everett after Mystic’s retirement. The two largest gas utilities in Massachusetts recently announced agreements with Everett to keep the LNG import facility operating for six more years, subject to the approval of the Massachusetts Department of Public Utilities. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.) 

ISO-NE has not been involved in the negotiations to keep Everett open beyond the end of the Mystic agreement. The station is on track to retire at the end of the agreement in the spring.  

The costs associated with the cost-of-service agreement have been substantial; ISO-NE estimated that it cost ratepayers more than $600 million in the first 18 months of the agreement. More than $200 million of this cost came solely from January and February of 2023, driven by the spike in global LNG prices.   

Everett’s primary operational conditions for these months were listed as tank management, which includes self-scheduling to run and burning off excess fuel to make room for prescheduled LNG shipments. 

“While we remain sympathetic to customers’ concerns regarding the high costs of the provision of fuel security by the Mystic units, we believe we have struck the right balance,” FERC wrote in its rehearing response. “We are not persuaded that providing the additional information … is necessary to verify Mystic’s costs and ensure that the Mystic agreement’s filed rate is accurately implemented.” 

The public power entities also challenged FERC’s ruling with the D.C. Circuit Court of Appeals in early February, writing that “the commission’s decision to prevent customers from verifying the justness and reasonableness of the charges imposed on them through the cost-of-service agreement is not supported by substantial evidence or reasoned decision making, as required by the Federal Power Act.” 

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GSA, DOD to Power Federal Facilities with 2.7M MWh of Clean Energy

The Biden administration wants to buy more than 2.7 million MWh of carbon-free electricity (CFE) per year to power hundreds of federal and military facilities across the 13 states served by PJM, according to a request for information jointly issued by the General Services Administration and Department of Defense on Feb. 9. 

The RFI also sets out an ambitious timetable for the procurement, which it describes as “one of the federal government’s largest-ever clean electricity purchases.” The official request for proposals could go out in May, with awardees announced in September and the first clean electrons going online by the end of the year.  

In line with President Joe Biden’s 2021 executive order establishing a 100% clean energy goal for federal facilities by 2030, GSA and DOD are looking to make half of the CFE procurement matched hour for hour with demand on a 24/7 basis.  

With over 300,000 buildings, the U.S. government is the nation’s largest energy consumer and “a steady customer prepared to make long-term investments,” GSA Administrator Robin Carnahan said in the RFI press announcement. “We’re using the government’s buying power to spur demand for clean, carbon pollution-free electricity, and we’re partnering with industry to drive toward the triple win of good jobs, lower costs for taxpayers and a healthier planet for future generations.” 

Brendan Owens, assistant secretary of defense for energy, installations and environment, stressed the link between clean energy and national security, and DOD’s leadership in “greening federal government operations.”  

“Today’s announcement will help facilitate grid transformation to address the climate crisis and to provide clean, reliable and affordable electricity that ensures mission resilience for DOD operations,” Owens said. 

The RFI specifies that the government is looking to procure the CFE through retail electricity contracts rather than traditional power purchase agreements. Contracts could be for up to 10 years, with fixed per-kWh prices.  

Critically, the government is only interested in retail contracts for “bundled CFE,” which means “the original associated energy attributes have not been separately sold, transferred or retired,” according to the RFI. Renewable energy certificates (RECs) are the most used measure of clean energy attributes, with each REC certifying that 1 MWh of new wind or solar energy has been put on the grid.  

“Unbundled” RECs or similar energy attribute certificates (EACs) can be sold separately from the power that produced them. Solar installers may sell them to bring down the costs of an installation, and utilities or other companies often buy them to meet state-level clean energy mandates, passing on the cost to customers through increased rates. 

In other words, the Biden administration wants to make sure that the EACs for any clean electricity used to power federal facilities will not be sold for profit or used as a substitute for putting additional, clean energy on the grid.  

The RFI specifically asks that retail electricity suppliers be able to track and document that that any bundled CFE does not include EACs that have previously been counted for a state renewable portfolio standard. Companies are also expected to be able to track and report how much of the CFE provided is matched hour for hour with demand.  

1 Million MWh for BGE

The RFI does not list the federal or military facilities to be powered with CFE or their locations, but it does provide some hints. 

GSA intends to include 650 accounts in the solicitation, with contracts possibly awarded in phases. 

The RFI also provides a list of the megawatt-hours the government will need in the service territories of each of the investor-owned utilities in the PJM states. Baltimore Gas and Electric leads the list with 1,031,740 MWh. The massive military base at Fort Meade is part of the utility’s service territory. 

Commonwealth Edison comes second, with 403,774 MWh, while 201,297 MWh will be needed for Pepco’s service territory, which includes the high concentration of federal buildings in Washington, D.C.  

All three utilities are owned by Exelon Corp., which also owns Delmarva Power (1,381 MWh) and Atlantic City Electric (2,273 MWh). How will Exelon and other utilities handle the additional clean power this procurement could produce? 

In a statement emailed to RTO Insider, Exelon said it has been “modernizing our [transmission and distribution] assets over the last decade, allowing us to continue delivering safe, reliable, affordable energy to our customers even with a growing share of renewable and distributed energy resources.” 

Exelon’s long-range plan calls for $31 billion in investments “to strengthen our infrastructure — both physical and IT — to prepare our assets for an influx of renewable energy sources. … When these sources are built — we will be ready to deliver the energy.” 

GSA does recognize that the size and scope of the procurement may mean it will have to be rolled out in phases, and the agency may not be able to get all the clean energy it wants at the time contracts are awarded. The RFI notes that “GSA is considering including minimum CFE requirements describing how much bundled CFE can be delivered and when.” 

In such cases, “it is anticipated that contractors will be required to provide traditional retail electricity supply to meet [GSA’s] requirements,” the RFI says. 

A key question is how much new clean electric power will be needed to meet the government’s procurement targets. The RFI specifically says any clean power that has come online since Oct. 1, 2021, could be awarded a contract. 

In addition, beginning in July, PJM began its new “first-ready, first-served” interconnection process aimed at clearing a backlog of 260,000 MW from its interconnection queue.  

According to a year-end post on the RTO’s website, it estimates it will be able to clear 300 projects totaling 26,000 MW for interconnection this year. However, the overlap between the PJM queue and the federal procurement could be minimal as the RFI differentiates the bundled CFE it wants to purchase from “grid-supplied” CFE. 

The comment period on the RFI will run through March 18. GSA is holding an “industry day” Feb. 20 to talk about the RFI with retail electricity suppliers and other stakeholders. For more information, email CFESupport@GSA.gov. 

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LADWP Poised to Join CAISO Day-ahead Market After Board OK

CAISO notched another victory in the competition to bring organized markets to the West on Feb. 13 when the Los Angeles Department of Water and Power’s oversight board authorized the utility to prepare to join the ISO’s Extended Day-Ahead Market. 

LADWP has yet to issue a formal announcement on a market decision and did not respond to a request for comment in time for publication of this article. But the resolution advanced by utility officials and approved by the Board of Water and Power Commissioners on Feb. 13 allows LADWP “to proceed with necessary activities, agreement preparations, and other related EDAM work that will be brought back to the board in the future for approval.” 

“We think this is a good move forward,” Fred Pickel, LADWP’s ratepayer advocate, said ahead of the vote. “While the benefits exceed costs, it won’t have as big of an impact as participating in [CAISO’s] EIM, probably, but the information that all parties will get by participating in a formal market of this type will likely enhance everybody’s understanding of both short-run and long-run impacts and needs.” 

LADWP would be the third entity to commit to the EDAM following commitments by six-state utility PacifiCorp and the Balancing Authority of Northern California, a joint powers authority that manages system operations for the Sacramento Municipal Utility District and five other publicly owned utilities. (See BANC Moving to Join CAISO’s EDAM.)   

The largest municipal utility in the U.S., LADWP has been participating in CAISO’s real-time Western Energy Imbalance Market (WEIM) since April 2021. EDAM will expand the capability of the WEIM by including trading of day-ahead energy, which requires increased coordination among participants. As it works to attract members, the ISO faces strong competition from SPP’s Markets+ day-ahead offering, which has generated especially strong interest in the Northwest.  

The commissioners offered no comments before approving the request, which LADWP officials, including General Manager Martin Adams, submitted in a Feb. 5 letter and accompanying resolution. 

“EDAM builds on the success of WEIM, providing additional benefits to its participants while increasing regional coordination, supporting policy goals of the state of California and meeting demand more efficiently,” the letter said. 

LADWP estimates EDAM will increase its net revenues by $20 million to $59 million a year, with most gains “expected to result from savings in adjusted production costs and enhanced EDAM transmission-related congestion transfers,” the officials said in the letter. LADWP realized nearly $149 million gross benefits from its participation in WEIM in 2023, according to CAISO. 

The utility expects to incur about $14.7 million in setup costs to join EDAM, including system upgrades, training and ISO onboarding fees. It also estimates $21.1 million in annual costs for ongoing participation in the market, mostly stemming from administrative fees. 

“Overall, EDAM presents a strong net annual financial opportunity while helping LADWP better integrate additional renewable generation, thereby minimizing curtailments and greenhouse gas emissions in its service territory and the Western region,” the letter said. 

Extensive Reach

While LADWP’s service territory is limited to the city of Los Angeles, its reach extends far into other parts of the West. The utility owns and operates more than 3,600 miles of transmission lines spanning five states, including half the capacity on the 3,100-MW Pacific DC Intertie linking the L.A. metro area with the Bonneville Power Administration’s area in the Pacific Northwest. 

LADWP’s other interstate transmission assets include 60% of the contract capacity rights on the Southern Transmission System line connecting Southern California with the Intermountain Power Project (IPP) in Utah, a 36% ownership stake in the Mead-Adelanto Transmission Project connected to Nevada, and co-ownership of the Navajo-McCullough Transmission Line between the now-retired Navajo Generating Station in Arizona and the McCullough substation in Nevada. 

The utility also controls about 8,000 MW of generating capacity, including the 1,900-MW coal-fired IPP, 15% of the output from the 2,080-MW Hoover Dam in Nevada, and 5.7% of output from the 3,300-MW Palo Verde nuclear generating station in Arizona. 

IPP is slated for conversion to an 840-MW natural gas-fired plant in 2025, including turbines capable of burning a fuel mixture containing 30% hydrogen. Last year, LADWP was authorized to convert its Scattergood Generating Station, the largest gas-fired plant in Los Angeles, to hydrogen. 

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CEC Approves $1.9B for ZEV Infrastructure

The California Energy Commission approved a plan for spending $1.85 billion over the next four years to expand zero-emission vehicle infrastructure across the state. 

The bulk of the money — $1.15 billion — will go toward infrastructure for medium- and heavy-duty ZEVs. That includes $130 million for zero-emission infrastructure at ports. The funding is for battery-electric charging as well as hydrogen fueling. 

For light-duty vehicles, the plan includes $658 million for ZEV infrastructure.  

The commission approved the investment plan for the Clean Transportation Program during its Feb. 14 business meeting. 

At least half of the money in the investment plan will be used to benefit disadvantaged communities. 

“We need to make sure that this is zero-emission refueling infrastructure for everybody,” said Commissioner Patty Monahan, the CEC’s lead commissioner for transportation. 

ZEV infrastructure is needed for residents of multifamily dwellings, rural areas, and dense places “that are suffering disproportionately from air pollution,” Monahan said in a statement after the vote. 

Monahan also noted that funding figures could change based on the state budget. (See Newsom Budget Would Trim Calif. Climate Spending.) 

“As we all know, this is a tough budget year,” she said during the commission’s meeting. 

Funding Sources

Funding in the investment plan comes from three sources: the state general fund; the Greenhouse Gas Reduction Fund (GGRF), which gets money from the cap-and-trade program; and the Clean Transportation Program, which is funded through a surcharge on California vehicle registration. 

For example, the plan allocates $230 million in GGRF money over four years for zero-emission drayage truck infrastructure. Electric school bus infrastructure will receive $125 million in each of the next three years from the general fund. 

The investment plan divides funding into general categories, with details of the programs to be worked out through the CEC’s solicitation process.  

In addition to funding for light-, medium- and heavy-duty ZEV infrastructure, the plan allocates $46 million for “emerging opportunities” in areas such as aviation, marine vessels and rail. And $5 million will go toward workforce training. 

The plan’s emphasis on infrastructure for medium- and heavy-duty ZEVs is due to the outsized impact conventional trucks have on air quality, the CEC said. 

Trucks account for roughly 2% of the 31 million vehicles registered in California. But they’re responsible for about 23% of on-road greenhouse emissions, as well as large shares of nitrogen oxides and particulate matter from the transportation sector. 

“For these reasons, medium- and heavy-duty vehicles represent a significant opportunity to reduce GHG and criteria emissions while focusing on a small number of vehicles,” the investment plan states. 

EV Charging Needs

California will require all new cars sold in the state to be zero emission by 2035. The state’s Advanced Clean Trucks and Advanced Clean Fleets regulations set timelines for transitioning medium- and heavy-duty trucks to zero emission. 

The CEC released a report in August projecting that the state will need about 1 million public or “shared private” chargers in 2030 to support 7.1 million plug-in electric cars. By 2035, the numbers are expected to grow to 2.1 million public or shared chargers needed for 15.2 million light-duty plug-in EVs. 

Currently, California has close to 94,000 public and shared private chargers, in addition to private chargers at homes and other locations. The CEC said in a release that funding in the new investment plan will result in about 40,000 new chargers across the state. 

Funding from other programs also will boost ZEV infrastructure. For example, the state is expecting to receive $384 million in federal funding through the National Electric Vehicle Infrastructure (NEVI) program. 

“Combined with previous investment plans, funding from the federal government, utilities and other programs, the state expects to reach 250,000 chargers in the next few years,” the CEC said. 

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FERC Meets at Howard Law School and Gets Update on OPP Activity

WASHINGTON — FERC got a presentation of its Office of Public Participation’s 2023 Annual Report at its monthly open meeting Feb. 15, which was held at Howard University’s School of Law. 

The law school was founded in 1869, at a time when there was a great need for lawyers who would help Black Americans protect their newly established rights, Chair Willie Phillips said at the start of the meeting, held in a moot courtroom at the school. 

“As the first Black chairman of FERC, as a graduate of this esteemed law school and as a great-grandson of a slave, it is not lost on me the significance of this moment,” he added. “And so, it is indeed a pleasure to be here with you, to be here with my colleagues, and to present this meeting and to conduct the business of the Federal Energy Regulatory Commission in front of the next generation of energy lawyers and practitioners.” 

In addition to Howard Law students and faculty, the audience included former FERC Commissioner Colette Honorable, now executive vice president of public policy at Exelon, and recently retired FERC Secretary Kimberly Bose, who is also an alumna. 

In addition to reaching out to potential future energy lawyers, FERC heard from its Office of Public Participation and how it is reaching out to the public after being founded in 2021. 

“Our Office of Public Participation is key to our continued efforts to involve members of the public in FERC proceedings that are important to them,” Phillips said. “Hearing from the public is essential to ensuring the commission continues to make decisions that are in the public interest.” 

The OPP is meant to empower, promote and support public voices in FERC proceedings, said acting Director Nicole Sitaraman. 

“Public participation is our sole focus, and to remind public attendees here today: OPP is a non-decisional office and has no role in FERC decision-making and contested proceedings,” she added. “This allows us to interact fully with the public, which includes open and contested cases.” 

In 2023, the office participated in more than 160 meetings all around the country with constituents including landowners, tribes, environmental justice leaders, university researchers, environmentalists, consumer advocates and small business owners. It also developed video workshops on the natural gas prefiling process, the fundamentals of intervening in a FERC proceeding and the process for filing comments. 

OPP also developed 15 educational resource documents, which were praised by commissioners for helping to translate the dense technical language it deals with into everyday English. 

“The explainers, in case you haven’t read them, are taking concepts like: How does an energy market work? How does a capacity market work?” said Commissioner Mark Christie, “and trying to put those extremely difficult, complicated concepts into something that someone who’s not in this business for years and years and years can understand.” 

The report also included the most common questions OPP gets when it is dealing with the public, which includes how to participate in FERC processes, how to deal with post-construction impacts of regulated facilities on private property and how to engage with FERC when projects it regulates bring up environmental justice concerns.

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Federal Researchers Flip Switch on OSW Research Array

Researchers have activated a new array of sensors off the New England coast to gather information that could improve the design and operation of wind energy generators. 

The equipment was set up over the past three months and on Feb. 15 began gathering data on wind and weather patterns as well as wildlife activity. 

The zone being monitored — south of Massachusetts and Rhode Island, east of Long Island — is a center of early offshore wind energy development in the United States. A small wind farm has been operating there since 2016, three larger facilities are under construction and plans for six lease areas there are in various stages of development. 

The efficiency of those wind farms will benefit from analysis of the wind and weather, and of the interaction between the ocean and atmosphere, the U.S. Department of Energy and the National Oceanic and Atmospheric Administration said Feb. 15. 

Seven surface buoys, two subsurface buoys and six shoreline field stations have been set up, along with three lidar buoys that can measure wind up to 250 meters above sea level. The Woods Hole Oceanographic Institution’s air-sea interaction tower near Nantucket will be used as well. 

Along with weather, the sensors will monitor the activities of birds, bats and whales over the next 18 months. Researchers hope to gain a better understanding of their patterns of movement in the area, and thereby analyze the effects of offshore wind construction and operation on wildlife. 

The effort is called WFIP3 — it is the third phase of the Wind Forecast Improvement Project funded by DOE and NOAA. The Pacific Northwest National Laboratory and Woods Hole are leading the weather component of WFIP3; Duke University is leading the wildlife component. 

DOE and NOAA said the first and second phases collected data to improve the accuracy of short-term land-based wind forecasting/modeling in the Great Plains and Pacific Northwest regions, respectively. 

The data generated by WFIP3 will be used to inform offshore wind generation siting and grid integration, as well as to advance weather and wind plant modeling.  

Dave Turner, manager of NOAA’s Atmospheric Science for Renewable Energy Program, said in a news release: “We want to use these insights to improve NOAA’s operational weather prediction models, which often serve as the foundational forecasts for the energy community in their daily management of their wind plants.”  

DOE’s Alejandro Moreno said: “Understanding the offshore environment better is a Grand Challenge that DOE and its partners are addressing to ensure that offshore wind can not only operate efficiently and sustainably, but also contribute to grid reliability in the energy system of the future.” 

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CAISO Releases Draft Interconnection Process Enhancements Proposal

CAISO on Feb. 8 released its final draft proposal out of its Interconnection Process Enhancements (IPE), its initiative to address the “unprecedented and unsustainable interconnection request volumes” submitted in the current and prior study windows. 

The draft refines the initial IPE straw proposal released Sept. 21, 2023. Among the changes are the development of a generic timeline expected to align with FERC Order 2023 requirements, tweaks to the implementation of the zonal approach and more detail on how to fulfill the 150% planned transmission capacity within each zone. 

“I just want to emphasize [that] the process we have right now is not working and will not get us to a reliable system,” Danielle Mills, principal of infrastructure policy development at CAISO, said at an IPE working group meeting Feb. 15. “So, we need fundamental change, and I know it’s a little scary, but we need to just all link arms and jump in together.” 

Mills emphasized that the IPE initiative is part of a broader set of changes designed to onboard new resources quickly and cost-effectively to meet California’s decarbonization goals. As part of the process, the ISO signed a joint memorandum of understanding with the California Public Utilities Commission and Energy Commission in December 2022 to establish a general direction. 

The goal of the initiative is to prioritize interconnection requests aligned with priority zones, called the “zonal approach,” where transmission capacity exists or is approved for development. Entities seeking to interconnect must go through a process in which they will receive a score based on project readiness that determines if they can enter the queue. 

Because of such high rates of interconnection requests (in 2023, Cluster 15 set a record at 541 requests), the ISO also asked for FERC approval to cancel the 2024 interconnection window to give it more time to study current requests, as well as to continue to refine the draft proposal. (See CAISO Seeks FERC’s OK to Shut 2024 Interconnection Window.) 

Data Transparency

In previous working group meetings, stakeholders emphasized the need for more information about where priority zones are located. 

In the draft proposal, the ISO identified that it would consolidate relevant information into a single document that provides line diagrams of interconnection areas and points of interconnection, identifies transmission constraints, and gives a list of substations within each zone and the transmission plan deliverability allocated for each constraint. 

Per Order 2023, heat maps will be available 30 days after a cluster study and 30 days after the restudy. The ISO is developing a heat map for Cluster 14, though it likely won’t be available 30 days after the cluster’s phase 2 reports are issued because Order 2023 applies to only Cluster 15 and beyond. 

Timeline Concerns

CAISO is seeking to implement its interconnection reforms — both its IPE proposal and Order 2023 compliance filing — at once.  

ISO staff plan to file the compliance proposal in April, though they are not sure when FERC will act upon it. Jeff Billinton, director of transmission infrastructure planning at the ISO, said because of that uncertainty, staff don’t expect to re-engage with Cluster 15 until the first half of 2025. Order 2023 compliance will have a negligible impact on clusters prior to 15, the IPE draft states. 

Stakeholders expressed concern over the intent to move forward with IPE changes while waiting on FERC’s approval, especially regarding site-control requirements. 

“There’s uncertainty about … your idea that there’s a certain timeline for re-engagement with Cluster 15,” said Jason Burwen, vice president of policy and strategy at GridStor. “Folks are going out to get site control, sign lease options and whatnot. As the timeline of uncertainty moves forward … folks are hanging on to land for even longer than they anticipated.” He asked if the ISO could make a definitive statement about site-control requirement timelines. 

Billinton responded that the timeline shouldn’t be too troublesome for entities seeking site control and interconnection in the Cluster 15 window. 

“The outermost deadline for having site control really is the commencement of the cluster study, which would be only, I don’t know, a few months after we re-engage with Cluster 15 and go through the validation process,” Billinton said. 

Chris Devon, director of energy market policy with Terra-Gen, asked if there was any chance FERC could move fast enough to expedite the timeline. 

“It is our intent to beg FERC for an order as fast as possible,” Billinton said. 

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FERC Rejects Pump Storage Projects Over Navajo Objections

FERC on Feb. 15 rejected preliminary permits for seven pump storage projects on Navajo Nation land, saying it will no longer consider projects that are opposed by host tribes. 

Preliminary permits give the permit holder priority for filing a development application while it conducts feasibility studies. It does not authorize access to project lands or any construction. 

The commission previously granted preliminary permits routinely, saying concerns about potential impacts could be addressed in subsequent licensing proceedings. Recently, however, it denied permits at federal facilities where the agency that operates the facility opposed the project. 

“We believe that our trust responsibility to tribes counsels a similar policy in cases involving tribal lands and accordingly, we are establishing a new policy that the commission will not issue preliminary permits for projects proposing to use tribal lands if the tribe on whose lands the project is to be located opposes the permit,” FERC said. “To avoid permit denials, potential applicants should work closely with tribal stakeholders prior to filing applications to ensure that tribes are fully informed about proposed projects on their lands and to determine whether they are willing to consider the project development.” 

Denied were five preliminary permit applications filed by Nature and People First Arizona PHS LLC (NPFA):  

    • the 2,250-MW Black Mesa Pumped Storage Project North; the 1,500-MW Black Mesa Pumped Storage Project East; and the 2,250-MW Black Mesa Pumped Storage Project South, all closed-loop systems on Navajo Nation land in Navajo and Apache counties, Ariz. (P-15233, P-15234, P-15235); 
    • the Chuska Mountain Pumped Storage Project, proposed for San Juan and McKinley counties, N.M. (P-15293-001); and 
    • the Chuska Mountain North Pumped Storage Project in Apache County, Ariz. (P-15309). 

FERC also rejected Western Navajo Pumped Storage’s proposed Western Pumped Storage 1 and Western Pumped Storage 2 in Coconino County, Ariz. (P-15314, P-15315) 

In contrast, the commission awarded preliminary permits Feb. 15 to Neptune Pumped Storage for feasibility studies of the 318-MW Elephant Rock Pumped Storage Project near Sixes River (P-15310) and the 550-MW Soldier Camp Pumped Storage Project on Lobster Creek (P-15311), both in Curry County, Ore. 

The commission approved the permits, which are good for 48 months, despite protests from environmental groups that cited concerns over the projects’ impact on water quality and quantity, aquatic resources, wildlife and habitats, and tribal resources. Some opponents said it was doubtful the state of Oregon would issue water quality certifications for the projects. 

But FERC ruled that because a preliminary permit does not authorize access to project lands or project construction, “addressing the commenters’ concerns at the permit stage is premature.” 

FERC said it sent 12 tribes identified by Neptune Pumped Storage as having a potential interest in the Soldier Camp project a copy of the notice accepting the application but none of the tribes filed comments. 

The Navajo Nation raised numerous objections to the projects proposed on its lands, including that developers had not sought its consent for use of the land or procured required clearances for preliminary biological investigations. The Nation also cited concerns over its water rights and potential impacts on rare and culturally important plants and wildlife and said the developers had failed to engage in “meaningful consultation.” 

| Navajo Land Department

The Navajo Tribal Utility Authority, a unit of the nation that provides electric generation, transmission and distribution, did not take a position on NPFA’s Black Mesa projects but said it “looks forward to robust cooperation, communication and transparency” as the developer pursued its application. 

“Despite substantial progress in recent years, thousands of homes on the Navajo Nation still lack access to electricity and other basic services,” the authority told FERC in January 2023. “Accordingly, NTUA recognizes the wide range of benefits that can flow from environmentally, economically and culturally responsible energy development on and around Navajo land, including the creation of well-paying, local jobs for Navajo residents.”  

In addition to its new policy, FERC’s acknowledgment of tribal concerns was reflected in the Office of Public Participation’s annual report, issued Feb. 15, which noted its participation in the Tribal Energy Equity Summit, “Just Transmission for a Just Transition” in Saint Paul, Minn. in May 2023. (See related story, FERC Meets at Howard Law School and Gets Update on OPP Activity.)

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FERC Finalizes Winter Reliability Standards from 2021’s Uri

WASHINGTON — FERC has approved new mandatory reliability standards on weatherization that implement recommendations that came out of its and NERC’s joint report on the 2021 outages caused by Winter Storm Uri. 

The outages caused by cold weather that week were worst in Texas, though other grids suffered shorter outages. Overall, 4.5 million people lost power and 210 people died during the storm. 

NERC adopted a two-phase process to implement recommendations from the FERC/NERC joint report on Uri, and FERC’s order Feb. 15 deals with the second phase. 

The EOP-011-04 standard requires utilities to include critical natural gas infrastructure on their load-shedding plans so they are not shut down due to a lack of power, exacerbating electric outages during cold weather, as happened in Texas. Balancing authorities must develop, maintain and implement operating plans with provisions for excluding critical gas infrastructure from interruptible load, curtailable load and demand response during cold weather. 

NERC also sought approval of standard TOP-002-5, which requires balancing authorities to have an operating process for weather events that includes a method for identifying extreme cold conditions, a method for determining a proper reserve margin for such conditions that takes into account operational limits of generators and a method for determining a five-day hourly forecast that accounts for all relevant operational considerations. 

FERC said ensuring natural gas infrastructure works during cold weather is an improvement over current rules. 

“Doing so will help ensure that deploying these programs in extreme cold weather conditions will not exacerbate natural gas fuel supply issues, which could constrain generating unit capacity and thereby threaten the reliable operation of the bulk power system,” FERC said. 

The proposal gives distribution and transmission providers 30 months to develop a plan, with the clock starting later this year. That led FERC in its order, and commissioners at their regular open meeting, to ask entities that can do so to comply earlier. 

“Utilities that can comply early with the mandatory implementation date, please, I implore you: Do so,” Chair Willie Phillips said.  

Commissioner Allison Clements seconded the call at the open meeting and in a concurrence to the order, noting some of the improvements are not required to be in place until more than three years from now. 

“The grid and customers won’t experience the full extent of these protections for at least three more winters,” Clements said. “I appreciate that NERC has worked hard to improve reliability standards and that the implementation timeline here is responsive to some concerns in the stakeholder process, which is important. But as I’ve stated at past open meetings, waiting years for new reliability standards to kick in, whether they be cold weather or cybersecurity requirements, is not reflective of the urgency these issues demand.” 

The industry has seen other cold winter events since Uri, with NERC and FERC working on another joint report from the cold weather experienced in January. 

FERC Delegates Settlement Authority to Enforcement Director

FERC also issued a policy statement tweaking how it handles enforcement actions that delegates authority to open settlement talks with subjects of investigations to the director of the Office of Enforcement. Previously, staff had to get permission from FERC commissioners themselves to take that step. 

The change is meant to streamline the settlement process so enforcement investigations are resolved more efficiently. 

“If and when enforcement staff receives a viable settlement offer from the subject, it will negotiate the applicable terms and thereafter present the written offer of settlement to the commission for formal voting,” FERC said in its policy statement. “Importantly, while the new process grants enforcement staff new discretion to commence and engage in settlement negotiations, it does not change the fact that it is the commission that ultimately determines whether a settlement of an investigation is in the public interest and should be approved.”

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Enviros, Consumer Advocates Join Regulators Urging PJM-MISO Interregional Planning

A bevy of consumer, clean energy and environmental advocates have joined state regulators in appealing to MISO and PJM to undertake more comprehensive interregional transmission planning.  

Clean energy groups and consumer advocates have banded together to send separate letters to MISO and PJM’s Interregional Planning Stakeholder Advisory Committee (IPSAC) to request a new approach to interregional planning.  

A collection of 13 environmental groups said there’s an urgent need for more transmission bridging MISO and PJM “from a reliability, economic and public policy perspective.” The letter was penned by the Rocky Mountain Institute and signed by the Union of Concerned Scientists, Advanced Energy United, Clean Grid Alliance, Sierra Club, Environmental Law and Policy Center, Natural Resources Defense Council, Americans for a Clean Energy Grid and Earthjustice, among others.  

“Despite the continued demonstration of need for enhanced interregional transmission between PJM and MISO, total buildout of interregional transmission continues to lag this demonstrated need,” the organizations said.  

Consumer advocates, including Michigan’s and Illinois’ attorneys general; the Citizens Utility Boards of Michigan, Illinois and Minnesota; the Indiana Office of Utility Consumer Counselor; and the New Jersey Division of Rate Counsel struck a similar tone in their letter. 

“Transmission planning is more cost effective and results in better outcomes for consumers when it is done comprehensively, transparently, and using multivalue drivers. The current siloed process forces ratepayers to pay more for less beneficial outcomes,” the offices wrote. They said MISO and PJM don’t have a process to “proactively plan and build large-scale transmission” across their seams.  

“The processes that do exist are reactive, difficult to navigate and small scale,” the offices added.  

The groups’ appeal to the RTOs’ IPSAC coincides with a similar letter from the Organization of MISO States (OMS) and the Organization of PJM States Inc. (OPSI), which also asked MISO and PJM to redouble efforts around interregional planning. (See OMS, OPSI Urge MISO, PJM to Invigorate Interregional Planning.) MISO and PJM are conducting an annual issues review to determine the need for a joint transmission study this year.  

Both the consumer and clean energy advocates said the RTOs could use a proactive, forward-looking approach to plan interregional projects, rather than the historical view of their system that they have relied on to pinpoint needs. The clean energy organizations said MISO and PJM would benefit from a standardized set of benefit metrics, shared system modeling and a more comprehensive view of project needs that merges reliability, economics and public policy instead of considering them one at a time in studies. 

Today, MISO’s and PJM’s planning limitations “result in minimal transmission buildout, higher costs for consumers, and a less reliable and resilient grid,” the clean energy groups said. They recommended MISO and PJM incorporate their members’ plans and generation expansion predictions into a long-range-style planning process that looks ahead about 20 years.  

“Given the demonstrated, and accelerating, need for more interregional transmission between PJM and MISO, we request that the IPSAC initiate a more proactive, comprehensive interregional transmission planning process than what is currently done today,” they wrote to MISO and PJM. They asked the IPSAC to host a series of stakeholder discussions or create a working group to design a revamped   planning process that can be kicked off with a study within one or two years.  

“Failure to do so will continue to commit ratepayers in PJM and MISO to overpaying for inefficient, balkanized regional solutions that do not take into consideration the billions of dollars in benefits from enhancing interregional transmission between the two RTOs,” they stated.  

Rocky Mountain Institute’s Claire Wayner said while MISO and SPP have been actively planning for their seam through the Joint Targeted Interconnection Queue, MISO’s and PJM’s seam has been overlooked.  

“There hasn’t been much, really nothing at the scale we need to enhance grid reliability and reduce costs for customers and further clean energy,” Wayner said in an interview with RTO Insider.  

Wayner said she suspects there aren’t enough resources dedicated to MISO-PJM interregional planning and that the grid operators are employing a “wait and see mentality” on FERC’s potential minimum requirement for interregional transfer capability. She said she was “thrilled” to see OMS and OPSI’s nudge by way of their joint letter. Wayner said she thinks MISO and PJM members are missing an opportunity to secure federal money for new interregional linkages through the Infrastructure Investment and Jobs Act.  

Wayner said new MISO-PJM lines could bring not only new generation onto the grid and relieve interconnection queues but also aid progress toward clean energy goals in states like Michigan and Illinois, which straddle MISO and PJM and have aggressive clean energy goals.  

“I think there’s a disconnect between what planning MISO and PJM are doing by way of their coordinated system plan and the IPSAC and what all of these least-cost decarbonization models are showing us we need,” she said.  

Beyond decarbonization, Wayner said stronger connections will help maintain reliability during increasingly severe weather events. She said there’s growing research showing that the nation will need “major, lateral transfers of power.”  

Wayner said she thinks MISO and PJM should reassess their existing coordinated system plan and Targeted Market Efficiency Project process and put in place a planning process that looks 20 years ahead and simultaneously considers multiple benefits. She said she’s “not impressed by the scope or scale of planning that’s happened between MISO and PJM to date” and said much of that planning appears to be motivated by Northern Indiana Public Service Co.’s 2013 complaint against MISO and PJM’s interregional efforts. She said MISO’s and PJM’s sole interregional market efficiency project and four batches of small TMEPs are “not the type of transmission that we need to build the grid of the future.”  

“We’re telling them, you need to reinvent your framework because it’s siloed and it’s not working,” she said.  

MISO and PJM are set to address regulators, consumer advocates and clean energy groups’ ask for better interregional planning at the March 1 IPSAC teleconference.