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November 14, 2024

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IPF24: New York Starts Another OSW Rebound

NEW ORLEANS — New York’s latest misadventure with offshore wind was impeccably timed, going public three days before a major industry summit. 

Its latest attempt to bounce back was equally well timed, announced one day before the head of the agency leading the state’s offshore wind development gave a keynote speech at the summit. 

New York State Energy Research and Development Authority President Doreen Harris said at the 2024 International Partnering Forum that the state is pushing forward and so should the industry. 

“I believe we need to take a pragmatic approach to how we face these challenges together, and how we find solutions together that will set us up for long-term success. Now is not the time to be complacent or wait it out, or hope these challenges will go away, or hope that someone else will find an answer.” 

Every Atlantic state pursuing offshore wind development from Maryland to Massachusetts has suffered contract or project cancellations. New York, with some of the loftiest goals, arguably has had the worst of it. 

Contracts totaling more than 4 GW awarded in the state’s first and second solicitations were doomed in October 2023 when the state rejected a request for higher compensation to developers facing soaring costs. (See NY Rejects Inflation Adjustment for Renewable Projects.) 

Provisional contracts totaling just over 4 GW awarded in the third solicitation were canceled because General Electric opted not to bring to market the large turbines planned for those wind farms. (See NY Offshore Wind Plans Implode Again.) That was announced April 19, three days before Oceantic Network convened IPF24.  

The steps in response were numerous and prompt. 

In November 2023, NYSERDA announced an expedited fourth solicitation to backfill the crater left by the October decision, and that solicitation has since yielded two provisional contracts.  

On April 23, NYSERDA issued a call for stakeholders to provide input on its fifth solicitation, which it plans to issue this year. Within that solicitation will be a request for proposals on how to reallocate $300 million in state funding for development of major supply chain components. 

Also on April 23, NYSERDA requested proposals for allocating $200 million in funds available for supportive manufacturing and logistics.  

“So many of you should see yourselves in the solicitation because it’s focused on the suppliers and how to build them domestically,” Harris told the audience at IPF24’s plenary session April 24. 

Meanwhile, the state is looking several years ahead, working on version 2.0 of its Offshore Wind Master Plan, and is looking farther out to sea, in deep water where floating wind turbine technology would be needed. 

New York’s offshore wind target still officially is 9 GW by 2035, but that increasingly seems like a placeholder while new lease areas are designated, the supply chain develops, onshore infrastructure is built and better deepwater technology is developed. 

“My friends, this is just the beginning,” Harris said. 

Multiple Iterations

Each of New York’s offshore wind solicitations has been different from its predecessor. The Request For Information issued April 23 will help determine how different the fifth solicitation is, and in what ways. 

The RFI suggests some significant changes. NYSERDA may: 

    • switch to a two-step bid process, with developers submitting initial proposals stripped of any dollar figures and follow-up proposals with price tags after NYSERDA provides feedback on the initial proposals; 
    • impose an information blackout, with no public disclosure of details of proposals or price tags all through the process until after the contract is finalized; 
    • require an award security of $10,000 per megawatt upon contract award; 
    • allow contract delivery term extensions for delays for reasons beyond the developer’s control, such as unavailability of key components or installation vessels; 
    • double the contract security sums; 
    • retain a portion of the contract security if the developer misses project milestones, rather than terminating the contract; 
    • define interconnection cost-sharing thresholds and cost-share allocation consistently across all proposals; 
    • make all offer pricing subject to inflation adjustment to protect ratepayers and limit attrition; and 
    • modify the formula for calculating the inflation adjustment to make it more accurately reflect offshore wind’s levelized cost of electricity. 

Harris told NetZero Insider that NYSERDA wants input from the industry on the potential framework for the fifth solicitation outlined in that RFI. 

“One of our goals in taking in that feedback is how to accelerate our timeline, our procurement timeline,” she said. “And one of the proposals that we have is to run our generation solicitation separate from the $300 million supply chain solicitation. It will have the benefit of accelerating the timeline of the generation procurement, but it will also — at least as we are theorizing it in this RFI — allow more flexibility for the developers to identify and advance supply chain investments.” 

New York has a continuing interest in working with other states to expand that supply chain, she said. The hope is that a region can accomplish more than one state. 

“The parochialism of the states has diminished somewhat, and very much we’re seeing this integrated supply chain emerge in ways that could be quite useful,” Harris said. “So, for example, if we have a $300 million supply chain focused on primary components, it very much could be the case that an OEM uses those funds to invest in New York for components that will serve another market. And that’s a good thing.” 

Harris said there is a dual role for NYSERDA in focusing on the long goal — preserving a livable state and planet — while dealing with the day-to-day bumps in the road to that goal.  

“Focusing on the projects that are under construction, focusing on the jobs that are being obtained, focusing on the benefits that we see coming to our communities, those are tangible and real,” Harris said. “And to me if your eye’s on the horizon, it allows you to pay less attention to the twists and turns that are naturally part of a transition. But you know, we’ve got to respond.” 

One thing she is less worried about is an increasingly frequent topic of conversation in the industry: the potential victory in the November presidential election of self-professed wind energy hater former President Donald Trump. 

Offshore wind spending is infrastructure spending that enjoys bipartisan support, Harris said, and the money flows freely to red states. 

“We actually launched our offshore wind goals during the Trump administration. And it has been extraordinary, actually, how much the industry has grown and changed since that time.” 

But no offshore wind projects were permitted during the Trump administration, Harris is reminded. 

“Permitting is a different matter,” she acknowledged. “Certainly, we need projects to advance through permitting to enter operations. Yes, we pay close attention to the federal context in that matter, because there’s a necessary intersection.” 

Additional IPF24 Coverage  

Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:  

Central Atlantic Region Prepares for OSW Development 

How Best to Address OSW’s Effects on Fisheries 

Interior Announces Updated OSW Regs, Auction Schedule at IPF24 

Louisiana Manufacturers Expand into Offshore Wind 

Moving Offshore Wind Beyond Contract Cancellations 

Offshore Wind Sector Leaders Emphasize Tailwinds 

Voices of the OSW Supply Chain, as Heard at Trade Show 

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Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan

DENVER — Backers of the West-Wide Governance Pathways Initiative want to move quickly on the first part of their proposed plan to shift CAISO’s governance to an independent entity, leaders of the effort told Western state energy officials April 25.  

The straw proposal released by the Pathways Initiative’s Launch Committee on April 10 outlines a “stepwise” approach for gradually transitioning much of the authority of the ISO’s state-run governance into an independent “regional organization” (RO). (See Western RTO Group Floats Independence Plan for EDAM, WEIM.) 

Effecting that transition is the initiative’s key mission as it attempts to lay the groundwork for a single Western electricity market that includes California and builds on CAISO’s Extended Day-Ahead Market (EDAM). 

“We’re not talking about market design in this group, we’re talking about governance, and that’s been the box we’ve stayed in,” CalCCA General Counsel and Director of Policy Evie Kahl, co-chair of the Launch Committee’s Functions and Scope Work Group, said at the spring joint conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in downtown Denver.   

Kahl was speaking on a panel moderated by Washington Utilities and Transportation Commission member Milt Doumit — also a Launch Committee member.  

“The problem we’re trying to solve is a perceived lack of independent governance in today’s CAISO Western Energy Imbalance Market [WEIM] and Extended Day-Ahead Market [EDAM],” Kahl said. 

Step 1 of the proposal entails elevating the “joint” authority the WEIM’s Governing Body shares with the ISO’s Board of Governors over WEIM and EDAM matters to “primary” authority, a move that would require FERC approval but not a change to California law, according to legal analysis performed for the Launch Committee. 

Launch Committee Co-Chair Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), said Step 1 was built on previous work done by the WEIM’s Governance Review Committee (GRC). 

“And that’s one of the reasons we’ve been able to move so quickly into a Step 1 recommendation, because so much of these challenges and discussions have taken place with the GRC,” Sporborg said. 

Step 2 would establish the RO as a legal entity and, after passage of required California legislation, transition the Governing Body’s primary authority defined in Step 1 to “sole” authority seated within the RO.   

Kahl told RTO Insider that Pathways backers are pushing for CAISO to this summer kick off the stakeholder process that would establish the Governing Body’s primary authority, with the hope the ISO would complete the relevant tariff revisions by late fall.  

Waiting on NV Energy

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

“Assuming all the entities who have expressed an intent to join EDAM as of April 10, 2024, execute implementation agreements, only one additional utility representing at least 10,000 GWh of load and located in the Southwest would be required to trigger the Step 1 governance transition,” the proposal says.  

PacifiCorp on April 26 became the first Western utility to announce it will sign such an agreement. (See related story, PacifiCorp Fully Commits to CAISO’s EDAM.) Other entities signaling their intent to join EDAM include the Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and PGE.   

“We are not counting NV Energy in [the assumed commitments], but NV Energy could trip the trigger,” Kahl told state officials.  

The Nevada-based utility is expected to decide on a market this year, multiple sources have told RTO Insider. A recent study by The Brattle Group indicated NV Energy would gain significantly more benefits from participating in EDAM than Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

Sporborg said PGE’s decision in favor of EDAM came down to an assessment of customer value based on studies by Brattle and Environmental+Energy Economics that examined benefits based on various market footprints. 

“We found that the EDAM footprint would provide benefits to PGE’s customers in all ranges of scenarios,” she said. “We also found Markets+ would provide benefits, but to a lesser extent.” 

PGE also determined that unwinding its current participation in the WEIM would reduce its financial benefits by about $20 million annually.  

Sporborg also noted PGE is a net purchaser in the electricity market and that “getting the right congestion protections for our load was incredibly important to us in our decision making.” 

First Step for Step 2

Kahl said Pathways backers will spend the latter part of the year working with California lawmakers to craft the legislation needed to fulfill Step 2 of the straw proposal, with a bill to be taken up in the 2025 session. Still, the group expects to stand up the new RO as a legal entity by the end of this year. 

“We do not need legislation to do that,” she said. 

After establishing the RO, Sporborg said, Pathways could seat an independent board and begin to work through market oversight issues. 

“I think that legislation helps smooth the path towards the RO’s ultimate destination, but that we can do many things and take a lot of action absent a legislative change,” Sporborg said. 

Oregon Public Utility Commission Chair Megan Decker asked Sporborg and Kahl how the Pathways Initiative can sustain its efforts both “financially” and “administratively.” The group, which so far has covered its budget from money pledged by supporters, recently was rejected for an $800,000 grant by the U.S. Department of Energy. (See Pathways Initiative Rejected for $800K in DOE Funding.)   

“We were disappointed not to receive a DOE grant, but we do have an opportunity to reapply, and based on the feedback we received [from the DOE], we think that we are in a much better position to have a more detailed and specific proposal,” Sporborg said. 

Sporborg added the group likely will seek more contributions from supporters. 

“It’s been a real challenge, honestly, to stand up a brand-new organization, without the kind of institutional budget that normally comes with a lot of these efforts,” she said. “I think that’s a unique part of this journey, and something that I’ve been really just glad about, which is the support we’ve gotten from a really diverse group of stakeholders.” 

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IPF24: Offshore Wind Sector Leaders Emphasize Tailwinds

NEW ORLEANS — The headline session of the 2024 International Partnering Forum veered heavily toward celebration and optimism for the U.S. offshore wind energy sector. 

There are other ways to view the industry, given its recent growing pains, but one after another, keynote speakers at the IPF24 plenary session emphasized the word “growing” while minimizing the word “pain.” 

Oceantic Network CEO Liz Burdock | © RTO Insider LLC

Roughly 3,400 people from 32 nations attended the four-day summit convened by the Oceantic Network, forming an appreciative audience for this positive message. 

Millions of tons of averted carbon emissions and billions of dollars in capital expenditures are riding on the offshore wind industry’s progress, and most attendees at IPF24 have a keen interest in one or both. 

“The days of talking about if and when are over. From this day forward, the discussion is centered on how fast and how much can we build,” Oceantic CEO Liz Burdock said. “Have you felt the shift from pilots and plans to industry and action? American offshore wind is venturing into a bold new era.” 

Doreen Harris, president of the New York State Energy Research and Development Authority, spoke of both the difficulty of creating this new-to-America energy sector and the importance of succeeding. New York had seen both sides of the coin in previous weeks, with completion of the nation’s first utility-scale offshore wind farm and the collapse of contract talks for three more facilities totaling 4 GW. 

“Turns out, doing hard things is hard,” Harris said. “So why in the face of unprecedented challenges should we carry on? Because deep down we know that even in the face of these hurdles, a clean energy future is possible and within reach, and we can very much do it together.” 

U.S. Deputy Energy Secretary David Turk | © RTO Insider LLC

Deputy U.S. Energy Secretary David Turk spoke of the taxpayer support poured into the renewable energy supply chain. 

“This is something we’re not just doing in offshore wind, but we’re doing it in a variety of others. We actually have an industrial strategy,” he said. “Instead of just leaving things to the whim of the market we’re trying to actually influence the market, restore a lot of that capability here in the U.S.” 

Turk added: “This is not a test that we can afford to fail … Let us know how we can be helpful, how we can do our part, how we can do even more as we face this absolutely, absolutely critical test.” 
U.S. Secretary of the Interior Deb Haaland took the stage to emphasize the need to install offshore wind generation in national waters, saying: “Our reality today is abundantly clear. Our mission to build a better, cleaner, more sustainable future has never been more urgent.” 

She also made two significant announcements: Interior has set the schedule for a dozen wind energy lease sales through 2028, starting in the Central Atlantic region in August 2024, and has streamlined the regulations on renewable energy development in U.S. waters. (See Interior Announces Updated OSW Regs, Auction Schedule at IPF24.) 

Addressing Challenges

But what of the challenges that have proved so stubborn in the past two years? 

Workforce, supply chain, ships, boats, transmission, factories, ports, delays, cancellations, inflation, interest rates? 

The problems are real, but they will be overcome, speakers said. A panel discussion at the plenary focused on the lessons learned and moving forward from them. 

U.S. Secretary of the Interior Deb Haaland | © RTO Insider LLC

Bloomberg News reporter Josh Saul, moderating the panel, noted setbacks including the cancellations of three provisional offshore wind contracts in New York, announced just five days earlier. But he also noted that analysts at Bloomberg NEF project a huge buildout in U.S. waters once the sector gets past its early challenges. 

He asked BP Offshore Wind Americas President Joshua Weinstein what pinch point he sees, and Weinstein offered not one but two: grid interconnection and ports. 

“These are highly localized in nature, both in respect to their footprint and impacts, and it’s really something that at the end of the day, the global supply chain can’t solve for us through balancing measures and other industry opportunities,” Weinstein said. 

“But we’re seeing excellent progress, we’ve seen recognition on the part of the states. The Northeast has absolutely been a leader in port development sponsored at the state level, we’ve seen that in multiple states, and also on the grid interconnection side, we’ve seen multiple initiatives over the past couple of years recognizing those limitations … really a recognition of the current and future generation needs of the coastal grid.” 

Saul asked Fugro Americas President Céline Gerson how to speed up projects. Better data integration and analysis would be a big help, she said. Uncrewed surface vessels also are very useful, she said. They are operating in the North Sea and could be operating in U.S. waters. 

“We’re not able to scale up those types of uncrewed vessels fast enough,” Gerson said. “So, my call to action is, what can we do together so that we can push from a regulatory standpoint the adoption of this type of technology. We’re working closely with the regulators right now.” 

Amanda Lefton, an RWE vice president, noted her company holds leases in three regions — the Atlantic, Pacific and Gulf of Mexico — that are very different and therefore have very different technical needs that must be addressed. The Gulf, for example, has lower average wind speeds than either ocean, except during hurricanes.  

So, turbines in the Gulf must be able to handle both wind speed extremes. 

“We’re going to need to partner with OEMs and others to develop that technology,” Lefton said. “And of course in California, we know that we need to evolve offshore wind for floating technology. And importantly from RWE’s perspective, we see floating technology not as a revolution but as an evolution. 

“RWE is no stranger to coming into [a] market and helping develop it from the ground floor.” 

Lefton, a former director of the Bureau of Ocean Energy Management, closed on an optimistic note, challenging use of the term “reset” as it so often is applied to the U.S. offshore wind sector. 

In the 39 months since President Joe Biden took office, 10 GW of capacity has been permitted in U.S. waters, the Inflation Reduction Act was enacted, promising billions of tax dollars to help build it, South Fork Wind has been completed, construction of Vineyard Wind is well underway, and construction of two more wind farms off the Rhode Island and Virgina coasts is scheduled to begin shortly. 

“We’re taking a massive step forward and some steps backwards, but we’re still progressing in the right direction, made really tremendous progress along the way,” Lefton said. 

Additional IPF24 Coverage

Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:  

Central Atlantic Region Prepares for OSW Development 

How Best to Address OSW’s Effects on Fisheries 

Interior Announces Updated OSW Regs, Auction Schedule at IPF24 

Louisiana Manufacturers Expand into Offshore Wind 

Moving Offshore Wind Beyond Contract Cancellations 

New York Starts Another OSW Rebound 

Voices of the OSW Supply Chain, as Heard at Trade Show 

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PacifiCorp Fully Commits to CAISO’s EDAM

PacifiCorp said April 26 that it will sign an implementation agreement to join CAISO’s Extended Day-Ahead Market (EDAM), making it the first entity to formally commit to either of the two day-ahead markets being offered in the West. 

The Portland, Ore.-based company, whose sprawling territory includes portions of six states, was the first utility to join the ISO’s Western Energy Imbalance Market in 2014 and the first to publicly announce its intent to join EDAM in December 2022.  

EDAM is currently in a stiff competition for participants with SPP’s Markets+.  

“We are excited to formalize our agreement to become a participant in the EDAM,” PacifiCorp CEO Cindy Crane said in a joint announcement with the ISO. “A modern, coordinated day-ahead market in the West is vital to optimizing the region’s energy resources so we can continue to provide reliable and affordable power to our 2 million electricity customers across six states.” 

PacifiCorp serves electricity customers in California, Idaho, Oregon, Utah, Washington and Wyoming, owns 10,833 MW of generating capacity, and operates approximately 17,100 miles of transmission. The entity was the first to join CAISO’s Western Energy Imbalance Market in 2014. 

Anticipation continues to build in the West over which day-ahead market various entities will join. While PacifiCorp’s announcement marks a major achievement for EDAM, the decision won’t surprise participants in regional market discussions. 

Four other entities have indicated interest in joining EDAM. In March, Portland General Electric and Idaho Power signaled their intent to join (See CAISO’s EDAM Scores Key Wins in Contested Northwest.) The Balancing Authority of Northern California and Los Angeles Department of Water and Power have also informed the ISO of their interest in joining.  

“The momentum we are seeing for participation in the EDAM is very gratifying, and PacifiCorp’s formal commitment brings better definition to the vision of a regional day-ahead electricity market,” CAISO CEO Elliot Mainzer said in the announcement. “This is a major piece of a truly collaborative effort to support reliability and affordability for electricity customers by leveraging resource diversity and transmission connectivity across the footprint of the Western grid. We now look forward to continuing working with additional valued partners in the West to take the next steps in a fully integrated regional market.” 

Markets+ notched a potentially big win this month after Bonneville Power Administration staff recommended the federal power agency choose Markets+ over EDAM, though BPA won’t issue a draft decision until this summer. (See BPA Staff Recommends Markets+ over EDAM.)

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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.