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November 17, 2024

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Decade of Strong Growth Forecast in Offshore Wind Sector

A new report charts sharp growth in the global offshore wind sector, with 2023 showing the second-highest year-over-year installed capacity jump ever.

The 2024 “Global Offshore Wind Report” by the Global Wind Energy Council (GWEC), an international trade association, indicates 75.2 GW of capacity had been installed worldwide by the end of 2023 and predicts 410 GW of additional capacity will be installed in the next 10 years — if present policy support continues and effective strategies are in place to support such growth.

Most of that growth is forecast for 2029 to 2032, GWEC said — 60 GW in 2032 alone — and much of it is expected to be driven by countries newly embracing offshore wind as a source of clean energy, such as Australia, Japan, Brazil and Poland.

The report also notes that installations are falling short of policy goals and indicates that permitting, financing, the supply chain and the grid are key to supporting or limiting factors in the growth of offshore wind.

The will to succeed is there, the report says, adding: “The priority now must be continued collaboration between industry and policymakers to overcome hurdles to rapidly scale up this crucial technology for the economic and environmental wellbeing of people and economies around the world.”

Announcing the annual report, GWEC CEO Ben Backwell said: “Installing almost 11 GW of offshore wind is the leading edge of a new wave of offshore wind growth. Policy progress — especially across the Asia-Pacific region and the Americas — has set us on course to regularly install record-breaking capacity annually and pass the 380-GW target set up by the Global Offshore Wind Alliance.”

In all, 10.8 GW of capacity was added in 2023, the report said, which was 23.7% more than was added in 2022. It was the second-highest increase ever from one year to the next, aside from the 208% increase in 2021 over 2020.

Problem Spots

The picture drawn by the report is not uniformly bright.

The U.S. wrapped up 2023 with just 42 MW of installed capacity, or 0.056% of the world total. With the completion of South Fork Wind and with continued progress on Vineyard Wind, U.S. installed capacity is much higher than at the end of 2023, but it is still less than one half of 1% of the world’s total.

A confluence of macroeconomic factors came together to slow U.S. offshore wind development in 2023, the report notes, with 7.7 GW of projects canceled outright or sidelined with canceled offtake contracts.

As a result, GWEC is now projecting 15 GW of offshore wind will be online in U.S. waters in 2030, a sharp decrease from the 25 GW it projected in last year’s edition of the report.

However, as of June 2024, “the situation is now steadily improving,” the report says, citing multiple policy changes announced by state and federal officials scrambling to get the nascent U.S. industry back on track.

Projects totaling 4.3 GW are now under construction in U.S. waters, and projects totaling 50 GW are in some stage of planning nationwide. State procurement targets announced so far total 84 GW over the next two decades.

The report identifies floating wind as another problematic area.

Floating turbines are expected to be an important part of the generation profile as hundreds of gigawatts of offshore electric generation are built because there is only so much water shallow enough for fixed-bottom turbines.

But floating wind is not evolving technologically as quickly as once expected. It is still more expensive than fixed-bottom offshore wind and the specialized equipment and infrastructure needed to build and install floating wind farms is limited or nonexistent.

Just 236 MW of floating wind was installed worldwide at the end of 2023, most of it in Norway and the U.K.

In the year since it published the 2023 report, GWEC has concluded that commercialization of floating wind is unlikely to occur until the end of this decade — three years later than it predicted in 2023 — and has reduced its 2030 projection of installed floating capacity by 22% to 8.5 GW.

The Path Forward

The report offers several suggestions for supporting the global growth of offshore wind in its 2024 report:

    • The financing of offshore wind construction must expand, including in the Global South, where investment in the emerging markets and developing economies lags far behind mature markets and the North.
    • Offshore wind can be a tool for decarbonizing industry, and the industrial sector can provide a non-government offtake mechanism for the electricity produced offshore.
    • The supply chain must be built, and then it must be supported with strong volumes and steady policies. Government rules such as local content requirements and trade barriers create additional hurdles. The offshore wind industry must do its part by embracing collaboration, standardization and sustainable innovation.
    • Permitting needs to proceed faster: Longer lead times raise project costs and exposure to risk.
    • Expanded offshore wind development creates an opportunity for governments to pursue economic and social regeneration along coasts, if well established policies are in place and the support of communities is secured.
    • The workforce needed for the campaign can be built by up-skilling and re-skilling; industry and local and federal governments should put holistic plans in place to accomplish this.
    • Modern and efficient grids are the foundation on which offshore wind and other renewables stand, and a common challenge is how to achieve them. Aligning grid infrastructure development with clear regulatory frameworks will foster a resilient energy system.
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Order 1920 Rehearing Requests from States Seek Bigger Role in Tx Planning

The states that filed for a rehearing of FERC Order 1920 on transmission planning and cost allocation either argue the federal regulator is overstepping its authority or want changes to the order to ensure it doesn’t upset ongoing regional planning efforts. 

Many states, or organizations that represent them, that commented earlier in the rulemaking process did not file for rehearing. But more than a dozen rehearing requests came into FERC from either states or organizations that represent multiple states, such as the National Association of Regulatory Utility Commissioners. 

NARUC told FERC it appreciated the outreach to states during the rulemaking process and through task force meetings on transmission policy. But the group filed for rehearing because the final rule rejected some key provisions from the Notice of Proposed Rulemaking and adopted others that could undermine the goal of efficiently expanding the power grid. 

“On rehearing, NARUC respectfully requests FERC address the necessary deference to and importance of the state agreement and consensus on planning and cost allocation issues outlined in the NOPR,” it said in a rehearing request filed last week. “The suggested changes will necessarily improve outcomes, reduce potential litigation and facilitate subsequent state siting proceedings associated with transmission projects.” 

The NOPR proposed a stronger role for states in cost allocation, but FERC backed off that and requires only that states in a given region have six months to come up with their preferred cost allocation. The relevant transmission provider could decide to ignore that and file its own proposal. 

The state agreement should be binding and subject only to FERC approval, NARUC argued. Transmission providers should have to detail their efforts on state outreach, and if FERC does not require its adoption, transmission providers should have to file details on any state agreement reached. 

“Order 1920 creates a process that integrates individual state energy policies and goals into transmission planning, creates extensive procedures for ‘consultation’ with states and acknowledges how state input will facilitate the planning process,” NARUC said. “But then the order establishes conditions that permit the transmission providers to completely ignore and not even report upon state input.” 

The majority on FERC pointed to a court precedent called Atlantic City in finding that transmission providers ultimately have the final say on whether to file cost allocation methods. The New England States Committee on Electricity argued that was not the case. 

“However, Atlantic City does not prohibit commission action under FPA Section 206, under which authority the commission has promulgated Order No. 1920,” NESCOE said. “Rather, Atlantic City simply affirms that transmission-owning utilities have filing rights under Section 205 that FERC may not revoke.” 

If FERC cannot grant rehearing on that, it should at least encourage transmission providers to voluntarily codify existing or new approaches that would put state alternatives before FERC, which would be consistent with the current practice in NYISO and SPP. 

“Including the state-agreed-upon cost allocation method in a transmission provider’s Section 205 filing is a lawful and rational means to effectuate in a concrete way the respect for the state role the commission articulates,” NESCOE said. “The more the commission is successful in encouraging transmission providers to include such voluntary commitments in their tariffs, the greater the likelihood … that states in the region will have comfort with moving forward on providing the approvals needed to actually get much-needed new transmission built.” 

The main thrust of NESCOE’s comments was that it did not want Order 1920 to mess with the implementation of recently enacted transmission planning rules where ISO New England has agreed with its state members on transmission plans that enact its members’ policies. FERC already has approved rules allowing the ISO to study scenarios developed with the states, but companion rules to competitively solicit actual transmission lines are pending. (See Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats.) 

“NESCOE shares a commitment to meaningful, long-term regional transmission planning reform and seeks to ensure that FERC-jurisdictional transmission rates remain just and reasonable and not unduly discriminatory or preferential,” it said. “In light of the progress in New England, NESCOE especially appreciates the commission’s acknowledgment that certain transmission planning regions already conduct regional transmission planning on a forward-looking, proactive basis and its intent not to undermine progress made in these transmission planning regions, and our goal is to set a floor, not a ceiling.” 

The Virginia State Corporation Commission and North Carolina Utilities Commission said they support the rule’s stated purpose and recognize the potential cost savings and reliability benefits that longer-term, comprehensive planning could provide to consumers. But they took issue with some aspects of the final rule, including its claim that states won’t subsidize others’ policies. 

“Because the same public policies included in planning scenarios, and ultimately embedded in selected transmission projects, are not required to be considered for purposes of cost allocation, it is far from clear how that bedrock principle of just and reasonable rates can be actualized under the final rule,” the two said. 

State policies like climate laws, which Virginia and North Carolina have enacted, are included in the long-term plan. But aiding their actual achievement is not among the benefits, so the state may pay too low a share for enacting its policy. The two suggested allowing transmission planners to do “baseline scenarios” that exclude state policies so it can be discerned how much the policies impact the other plans. 

North Carolina and Virginia regulators also were skeptical of the proposal requiring utility and corporate “goals” to be included in the long-term transmission plans because they are easily changed, or even abandoned. 

“This may ‘skew’ information submitted in the stakeholder process in favor of utility or corporate interests and result in planning scenarios that give too much weight to ‘goals’ that are unlikely to be achieved,” the SCC and NCUC said. 

Other rehearing requests from states were more strident in their opposition to FERC’s Order 1920, arguing the commission overstepped its authority in the Federal Power Act and violated the “major questions doctrine.” 

A group of Republican state attorneys general (from Texas, Alabama, Arkansas, Florida, Georgia, Idaho, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, North Dakota, Oklahoma, South Carolina, South Dakota, Tennessee and Utah) argued FERC is trying to use the planning and cost allocation rule to implement the Biden Administration’s green energy policies. 

“It shifts transmission costs for those remote renewables to consumers under the guise that those consumers will ‘benefit’ from those resources, without considering whether less remote resources of any type might be less expensive, more reliable and environmentally beneficial,” the attorneys general said. 

The filing was coordinated by the Texas Attorney General’s office, and it noted that the states aren’t opposed to renewable energy, with the Lone Star State leading the country in terms of megawatts of renewables installed.  

“The commission’s claim that the rule’s proposals are necessary to ensure just and reasonable rates stretches the FPA beyond its limits,” the attorneys general said. “Indeed, the proposals set forth in the rule will not — and are not designed to — ensure just and reasonable rates; they are blatantly preferential and would harm consumers by shifting costs to load, not protect them.” 

A group of state regulators used language similar to those attorney generals, with the Louisiana PSC, Mississippi PSC, Arkansas PSC and South Dakota PUC also arguing that while they are not against renewable energy, they are opposed to Order 1920’s usurpation of state authority. 

“The commission is attempting to do indirectly what it is prohibited from doing directly: usurp the states’ exclusive authority over generation choices by instituting planning rules designed to benefit remote generation, and that generation’s developers, over local generation and to shift billions or trillions of dollars in transmission costs from those developers onto electric consumers,” they said. 

The Arizona Corporation Commission said the order violates the major questions doctrine and would preempt its authority, while “unmistakably promoting a ‘net zero’ policy agenda.” 

“The final rule seeks to recast FERC as a national integrated resource planner with extraordinary powers to oversee and dictate to all public utility transmission providers in the country, in RTO and non-RTO regions, detailed instructions on planning transmission that fulfills the current presidential administration’s stated preferred policies,” the ACC said. 

The West Virginia PSC was more moderate in its criticism, noting that it supported the NOPR, but FERC’s decision to pare back state regulators’ input over cost allocation made the longer-term planning horizon and new mandatory benefits no longer just and reasonable. 

“That substitute, the engagement period and de minimis requirements placed on transmission providers, is so far removed from state cost allocation involvement that was noticed that the cost allocation and state agreement requirements in the final new rules must be re-noticed to give the public an opportunity to comment,” the PSC said. 

West Virginia is a member of the Organization of PJM States Inc., which filed its own rehearing request, also arguing states should have more of a guaranteed say over cost allocation. 

“If states, through the process envisioned and required by the commission, exert the effort and resources to successfully reach agreement on a cost allocation method or methods and transmission providers are not required to file or even acknowledge the relevant state entities’ efforts, state engagement in the development of cost allocation methods for long-term regional transmission facilities and any expected development of more efficient or cost-effective facilities may never materialize,” OPSI told FERC. 

In other words, giving states more authority would make them more likely to actually get steel in the ground.  

OPSI was one of several organizations that argued the six months to come up with a state agreement could easily prove too short, given state regulators’ other responsibilities. FERC should allow for an extension to 12 months total if states unanimously agree that would help them come up with cost-allocation rules. 

The PUC of Ohio’s Federal Energy Advocate filed comments noting that while the state has found RTO membership beneficial so far, Order 1920 could change that. RTO membership was based on assuring reliable transmission systems at the least cost. 

Order 1920 “puts these principles in the rear-view mirror,” the Ohio regulator said. “Instead, it attempts to look 20 years into the future to launch a massive program today, not focused on achieving reliability at just and reasonable rates, but rather on building transmission projects to satisfy the ambitions, goals and policies of corporations, developers and governments that are not connected to reliability. Nothing could be further from the principles of Order No. 1000 and the requirement under the FPA for the commission to ensure just and reasonable rates.” 

The Ohio commission supports the use of the existing State Agreement Approach, which so far has been used only by New Jersey, where PJM planners helped it save money on interconnecting the wind farms called for by its policies. But the rehearing request argued that would no longer be feasible under Order 1920 because the SAA is focused on state policies alone and ignores other benefits the lines produce — limiting cost allocation to the states that agree to it. 

The Ohio regulator noted that New Jersey has decided to pause on moving forward with another use of the SAA as the Garden State weighs the implications of Order 1920. 

“FERC must not let RTO membership devolve into an instrument by which states are pitted against one another in a zero-sum game of cross subsidies amongst competing policy interests,” the Ohio commission said. “Such a development would undermine the value proposition of RTO membership for states who do not wish to subsidize the policy preferences of others, directly contradicting FERC’s goal of encouraging RTO participation as envisioned by FERC Order No. 2000.” 

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EIA: Dispatch of Coal Generation Falls in PJM

Analysis from the U.S. Energy Information Administration finds that the average runtime for PJM coal-fired generators has declined sharply over the past decade because of increasing fuel and start-up costs.

The agency’s June 17 “Today in Energy” report said the RTO’s coal-fired power plants ran at an average of 34% of their maximum output in 2023, down from 56% in 2013.

That resource class made up 14% of generation available to PJM and 18% of capacity last year, compared with 44% and 38% a year earlier. About 34 GW of coal generation retired over that period, and an additional 2 GW was shifted to other fuel sources. EIA attributed much of the change to competition from the growth of efficient combined cycle gas generation.

The strain of repeat starts and stops can increase maintenance costs for thermal generators designed to operate at a constant rate, meaning that when PJM is selecting the lowest-cost resources for dispatch in the energy market, it’s often uneconomic to start an offline coal plant.

“Coal-fired generating units are generally designed for steady-state operation, and they operate with the fewest problems when they run all the time,” EIA wrote. “Restarts can be costly because large thermal plants can experience problems caused by repeated start-ups and shutdowns, increasing maintenance costs. The restart cost can be a key factor in determining plant operating strategy. … Because those restart costs increase their market offer, coal plants, when competing against other sources, may not be selected to operate.”

The changing economics hit independent power producers particularly hard, with 24 GW of IPP-owned coal generation deactivating over the past decade, leaving 17.6 GW on the grid. IPPs lack the cost recovery mechanisms that allow regulated utilities to mitigate financial risk for their generators, EIA said.

In an email to RTO Insider, PJM’s Dan Lockwood said the findings appear to be in line with a white paper the RTO published last year, which found that retirements of thermal generators could outpace the development of new resources through 2030. (See PJM Chief: Retirements Need to Slow Down.)

“As PJM pointed out in its ‘Energy Transition in PJM: Resource Retirements, Replacements & Risks’ study issued early last year, a confluence of conditions — including state and federal policy requirements; industry and corporate goals requiring clean energy; reduced costs and/or subsidies for clean resources; stringent environmental standards; age-related maintenance costs; and diminished energy revenues — are leading to an overall decline in the use of thermal resources, including an increase in coal unit retirements,” Lockwood wrote.

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FERC Requests Briefings on SEEM After DC Circuit Order

FERC on June 14 called for stakeholder briefings on the Southeast Energy Exchange Market (SEEM) as a step toward satisfying a D.C. Circuit Court of Appeals order last year remanding the commission’s approval of the market (ER21-1111, et al.).

The vote was 2-1, with outgoing Commissioner Allison Clements filing a dissent calling the commission’s briefing request “a dead end” that “ignores the court’s explicit conclusion” on SEEM’s fairness.

SEEM has been controversial since it first was proposed in 2021. Its founding utilities, which included Duke Energy, Southern Co., Dominion Energy, and LG&E and KU Energy, contended the market would reduce trading friction and promote the integration of renewable resources through automated trading, elimination of transmission rate-pancaking and allowing 15-minute energy transactions.

However, some opponents argued the market would favor transmission-owning utilities and promote monopolistic behavior, while others pushed for alternative structures like an RTO.

FERC’s latest order arises out of legal wrangling that began with the commission’s original approval of the SEEM agreement in 2021. At the time the commission had only four members, who split 2-2 when the deadline for approval arrived. Under the Federal Power Act, in such a situation the measure under consideration is automatically considered approved.

As a result, the SEEM agreement became effective by operation of law. FERC later approved — by majority vote — revisions to the agreement along with the market’s non-firm energy exchange transmission service (NFEETS) and tariff revisions by the founding utilities. (See FERC Accepts Key Tariff Revisions to SEEM.)

A consortium of environmental groups including Advanced Energy United, the Clean Energy Buyers Association and the Southern Alliance for Clean Energy, which had opposed SEEM since its original proposal, filed a request for rehearing in 2021. FERC denied the request, claiming it was submitted after the 30-day deadline for rehearing motions expired.

The opponents then appealed the denial to the D.C. Circuit, which agreed their request was filed within the deadline and remanded the approval back to FERC. (See DC Circuit Sends SEEM Back to FERC.) The court also found FERC failed to adequately explain why SEEM should not be considered a loose power pool under Order 888. Opponents had argued NFEETS made the market a loose power pool, which under FERC’s rules must be open to nonmembers.

FERC’s order last week stopped short of addressing the court’s directives. Instead, the commission’s majority called for “supplementing the record” with briefings from stakeholders on whether SEEM qualifies as a loose power pool and whether the market’s requirements that entities transacting in it have a source and sink inside its footprint violates Order 888.

The commission provided a series of questions that respondents should answer, including:

    • whether SEEM is a loose power pool;
    • if so, whether and how SEEM “is consistent with or superior to the open-access requirements for loose power pools” in Order 888;
    • if SEEM is not a loose power pool, whether and how it is superior to or consistent with the pro forma open access transmission tariff;
    • whether NFEETS should be considered a non-pancaked rate;
    • whether NFEETS is “comparable to traditional transmission arrangements in bilateral markets”; and
    • whether entities with a source or sink outside of SEEM’s territory could conform with the technical requirements of the market’s matching platform.

Stakeholders must submit their responses within 60 days of the commission’s order; reply briefs are due 30 days thereafter.

Clements Says Briefings Only Delay the Inevitable

In her dissent, Clements argued the commission was only delaying an inevitable recognition that its “previous decision-making [on SEEM] was arbitrary and capricious.” She cast the court’s decision as a vindication of those who have questioned SEEM’s usefulness and fairness.

“Commissioners supporting SEEM have constructed a straw man, attempting to dismiss my and petitioner’s concerns as stemming from a desire for a full Southeastern RTO, of which SEEM falls short,” Clements wrote. “But my concerns have been and remain focused only on … whether SEEM as proposed is legal under the requirements of the Federal Power Act, Order No. 888 and Order No. 888-A.”

Clements insisted the court’s “clear conclusions and directives obviate further record development” that would only serve to further waste “the valuable time of stakeholders we ask to engage in these proceedings.” Concerning FERC’s question about whether SEEM’s geographic requirements are necessary for it to be technically feasible, Clements asserted the court already had determined that such necessity “does not render the construct permissible.”

Clements concluded by pointing out the court last year ordered FERC to consider both the Order 888 questions as well as the requests for rehearing. She emphasized that “the majority’s order fails to accomplish either task.”

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Why Gene Rodrigues Came out of Retirement to Lead DOE’s Office of Electricity

WASHINGTON ― After 23 years working on demand-side programs at Southern California Edison and another eight as a consultant at ICF International, Gene Rodrigues was four months into retirement in 2022 when he got “the call,” to serve as assistant secretary at the Department of Energy’s Office of Electricity. 

“There were two things that made this irresistible to me,” Rodrigues said in a recent interview at DOE headquarters. “I saw this as my opportunity to give back … my opportunity to actually serve all the American people.” 

Rodrigues felt a more personal pull as well. “I’m the son of a father who was a career military person and a mother who came from her native land and became a U.S. citizen,” he said. “So, it was engrained in me since I was a kid growing up around parents with that kind of background that serving the public is not just something you do; it’s an obligation that we all have, and this was my opportunity to kind of honor my parents in the same way.” 

Known for his deep industry knowledge and engaging personality, Rodrigues aced his confirmation hearing before the Senate Energy and Natural Resources Committee and was sworn in as DOE’s assistant secretary for electricity delivery and energy reliability on Jan. 9, 2023. In practical terms, his main job is leading the Office of Electricity (OE), which works with DOE’s 17 National Laboratories “on solving really big problems, making discoveries and breakthroughs around everything from battery chemistry to materials science … that will help us to advance the grid; to make a truly 21st-century grid,” he said. (See Former NRG CEO Faces Tough Questions at Senate ENR Hearing.) 

Rodrigues sees the OE as part of a continuum running from the labs to DOE’s Grid Deployment Office (GDO), which has been awarding billions in funds from the Infrastructure Investment and Jobs Act to help utilities upgrade their distribution and transmission systems. OE does the science ― and gets fewer headlines ― and GDO does the infrastructure, he said. 

“We take basic science discoveries and prove them out through research and demonstration activities that help the market to get confidence in these new technologies [and] new operational approaches,” Rodrigues said. The OE focuses on advances in “components and systems, in controls and communications and in grid-scale storage, making them not just accessible but trusted by the folks who are making massive investments, and that helps to accelerate their adoption in the real world.” 

In May, for example, the OE awarded $15 million in grant money to three projects demonstrating different long-duration storage technologies, including vanadium redox flow batteries and supercapacitors, both of which can provide 10 hours or more of storage. 

Rodrigues sat down with RTO Insider for a wide-ranging conversation on the work that OE is doing and why he spends a lot of his time, not in his D.C. office, but in the field, working with utility representatives, regulators and customers, all looking for new solutions to the core problems of the energy transition. The quotes from the interview here have been edited and condensed. 

RTO Insider: We know DOE is looking at the role of artificial intelligence in advancing and accelerating the energy transition. What role does the OE have in that? How can it use AI to bridge some of the gaps in technology and policies? 

Rodrigues: “We aren’t the shop that specifically works on it, but within science and innovation, we have folks who are 100% focused on what are the potentials of using AI that can help us leapfrog to make the grid even more reliable, resilient and secure. When you look at the grid, you see this incredibly complex network of poles and wires connected to generators, both large central station in faraway places and the solar panels on the roof of my house, connected to a whole bunch of devices in the home. So, it’s absolutely clear to me as the assistant secretary for the Office of Electricity that we can’t train people to be able to operate a system that complex at the speed of the flow of electrons through wires. But guess what? We can use distributed intelligence to help people make one wise and virtuous choice to participate in a program that helps them financially, helps them with reliability and resilience, but also helps manage this increasingly complex grid. That’s the incredible promise of artificial intelligence.” 

We can’t talk about AI without talking about data centers, the increasing amounts of electricity they will need and how some utilities are reacting, saying they need to build more natural gas plants. What’s the way forward here? 

“Utilities and the folks who are building these data centers, what they have to do is start working in a way that’s more collaborative than in the past because that collaboration allows two things to happen. No. 1, it allows the utilities to plan thoughtfully about where and how to best serve that load using their existing system and whatever expansions are required, [and] how that process can be expedited. The second thing is some of these large data centers are looking at how they can be a constructive participant in the load by using load flexibility. Sometimes these data centers are [built] by firms that have data centers in different parts of the country, and they can move some of that computing load from one place to another to help balance out the energy. And so those are very, very interesting opportunities.” 

One thing we’ve been hearing a lot about at industry conferences is the need for new approaches to cost and risk allocation. Do you see any opportunities there? 

“I think there’s some genius in rethinking cost allocation and risk sharing in our industry, and let me suggest one thing here as an example. In today’s world, we have the potential to make suboptimal decisions around transmission planning and investment if we allow ourselves to be boxed into thinking that an individual utility should only look at the costs incurred in its service territory and try to offset them only with the benefits that are accrued in that service territory. 

“As we have more interconnections for broader geographies, it allows you to do two things on a reliability and resilience foundation. It allows you to import energy when needed to make up for [when] a storm goes through and you lose some generating capacity locally. But on the other side, it allows you to export energy to a wider area of our nation in ways that might create economic opportunity for the people within a state. So, as we think about how to justify cost and transmission investments, we need to be thinking not just in terms of the artificial boundaries of a service territory in the region, but how interconnections outside of a service territory and even between regions can be truly cost-effective investments in ensuring not just reliability, but resilience.” 

Covering utilities and conferences, we always hear about pilots and demonstrations but not necessarily how a utility is expanding a pilot across its systems. How does the industry break out of this perennial cycle of pilots and risk-averse utilities and regulators? How are you doing that at OE? 

“There’s an old joke in our industry, that every utility wants to be the first to be second. And that makes sense when you think about the awesome responsibility of ensuring reliability. It’s awfully hard to move away from what’s been proven in the past over and over and over again. But I would say this: I think progressive utility leadership and progressive regulators and policymakers are understanding the issue that the energy field is changing in such a way that just relying on the techniques and the tools and the products and the approaches of the past is not the safe approach. 

“That is why it’s so important for me in this bridge role between basic science of discovery and deployment, to not sit here in the office and just write white papers about how keen and wonderful technologies are but actually to go out and work with utilities and utility associations in partnership to overcome whatever hurdles they have. Some of it is certainty about economics. We have a tool coming out of our office ― Reconductoring Economic and Financial Analysis (REFA) ― and the idea is that because reconductoring is not something that’s been done time and time again throughout the industry, we’ve created a tool to help decision-makers in the utility and in the regulatory bodies to assess the economic benefit of reconfiguring an existing transmission thoroughfare with high quality, highly efficient, advanced technology. 

“Our folks here in the Office of Electricity ― it’s kind of a fun thing we do ― I always talk to them about impact [slams hand on table], and I always slam the table when I talk about impact because that is really what our job is. It’s not just to do research, development and demonstration, but it’s to ensure it gets adopted in an accelerated fashion and at scale in the real world.” 

Do you have any success stories you can share? 

“When the supply chain issues started being raised by industry and brought to the table here in the Department of Energy, the tip of the spear was distribution transformers. We brought together a convening of manufacturers, the folks who produce electrical steel, the folks from utility associations, all of them came to the table, and we discovered some things. One was there was simply way too much diversity in the design specifications for these transformers, and that slowed down the ability of manufacturers to build [them]. And we discovered that there was too little flexibility in the specification of individual components; so, if you said, ‘I want [a certain] component,’ and that wasn’t available, then it stopped your ability to complete a product instead of using something else. 

“So, we added representatives from EEI, APPA, the public power folks and rural electric co-ops ― got their engineers around the table with the manufacturers, and we facilitated discussions around how could we put together a matrix of components substitution, so that we would get out of this problem of running into a bottleneck when one component wasn’t available. And the other thing they are doing, and they’re continuing to work on as we speak, is how can we maybe bring a little more rationality to the diversity in distribution transformer design?” 

One of the ongoing challenges of the energy transition is just getting public buy-in on the need for more transmission. Everyone wants clean, reliable, affordable power; they want more of it, and they want it faster, but no one wants wires anywhere near where they can see them. How can the OE address that? 

“The answer to that is fairly clear. You can’t look at transmission and sell it on its technological features, even though the folks who have engineering degrees in our department love to talk about how high-tech the components and systems are that we work on. I think we really have to get to a conversation in this country that gets people to lose their sense of complacency about the engineering marvel that it is that when you push a switch, the lights come on. We’ve had over a century of that kind of reliability, and we’ve just taken for granted all this engineering, economic magic that just happens in the background. You don’t need to think about it.  

“It is time for policymakers, for regulators for legislators, for people planning and operating and investing in the grid to think about it. So, will transmission ever be sexy? I don’t think so. But it should be more in front of mind because we have options available to us today that will help us to ensure reliability, resilience, security and affordability into the future. And if we don’t think about, consider and adopt and even embrace those new technologies and new approaches, then we’ll be mired in the approaches of the past. And that’s not how to lead the world in a giant, clean energy revolution that is being undertaken as we speak.” 

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TOs Approve Transferring Transmission Plan Filing Rights to PJM

Transmission owners have approved transferring filing rights over PJM’s planning protocols to the RTO through a package of amendments to the Consolidated Transmission Owners Agreement (CTOA).

The June 13 vote at the Transmission Owners Agreement-Administrative Committee (TOA-AC) greenlights the revisions to be filed at FERC, following a May 31 communication from the PJM Board of Managers announcing it had agreed to the proposed amendments.

The proposal would remove Schedule 6, which details the Regional Transmission Expansion Plan (RTEP), from the Operating Agreement (OA) and create a new corresponding Tariff Schedule 19. The proposal would also move the RTEP dispute resolution processes to the Tariff and cleanup references and definitions to point to the Tariff instead of the OA. During the May 6 MC meeting, PJM Associate General Counsel Jessica Lynch said the substance of the RTEP would remain unchanged by the shift.

Shifting the RTEP process to the Tariff would allow PJM to revise its planning processes through a Federal Power Act (FPA) Section 205 filing, which would not require the endorsement of the PJM membership and would not require a finding that the existing governing documents are unjust and unreasonable, as would be the case with a Section 206 complaint. The PJM board communication also stated that the 60-day timeline for FERC to respond to a 205 filing would allow faster action when prompt action is needed.

“It has become very clear that PJM will need to be more proactive and nimble in its planning efforts. As has been referenced in prior discussions, most all other ISOs/RTOs (and indeed virtually all other transmission planning public utilities in the United States) have Federal Power Act (FPA) Section 205 filing rights over transmission planning, which allows these entities to independently propose rules to FERC, and perhaps most importantly, receive a reaction from FERC, whether positive or negative, within 60 days. The Board views this ability to receive feedback from FERC in a timely manner as strategically important in determining how best to plan the PJM system for the energy transition in the coming years,” the board wrote.

The Members Committee voted against endorsing the revisions during its May 6 meeting, where the changes received 25% sector-weighted support. Several stakeholders argued that empowering PJM with unilateral filing rights over regional transmission planning would allow it to bypass the stakeholder process and that the proposed dispute resolution process included would create an inappropriate barrier to MC endorsed OA amendments being filed at FERC. (See Members Vote Against Granting PJM Filing Rights over Planning)

During the May 8 Public Interest and Environmental Organization User Group (PIEOUG) meeting, Ari Peskoe, director of the Electricity Law Initiative at Harvard University, said the language would allow create a “shadow governance” where CTOA signatories could challenge PJM prospective Section 205 filings, PJM regional plans, or other PJM actions through a confidential mediation process. He also argued that it would allow utilities to pre-empt PJM planning by submitting similar, but more expensive, projects of their own. (See Consumer Advocates, Environmentalists Urge Holistic Thinking at PJM)

Peskoe told RTO Insider he believes the CTOA amendments would violate the FPA and should be rejected by FERC. He said it’s unfortunate the PJM board accepted the agreement.

The May 31 letter from the PJM board said the RTO continues to value the stakeholder process, however there may be times that changes are needed even in the face of a deadlocked membership.

“As PJM has stated many times, having FPA Section 205 rights will not curtail stakeholder discussion of planning matters – never has it been more important to have stakeholders weigh in on the issues before us. But should Member consensus be unattainable, having FPA Section 205 rights will allow for PJM to still move forward with an FPA Section 205 filing with FERC, and in turn, receive a timely reaction from the Commission on a given planning rule change. This will better position PJM to continue to fulfill the reliability needs of consumers as we advance through this energy transition.”

Exelon Director of RTO Relations & Strategy Alex Stern told RTO Insider that the proposal would reinforce PJM’s independence and ensure that PJM, as the FERC-jurisdictional public utility, holds the authority to act when it determines reliability warrants change. He said that authority would be no different than what exists today for the RTO on the markets side.

“These revisions are a big step that those who own transmission don’t take lightly,” he said. “They afford PJM greater independence to plan the energy grid. This requires stakeholders, including Exelon, to compromise. However, to support reliability during the energy transition, Exelon believes it is critical that PJM has every tool at its disposal.”

As the PJM board noted in its May 31 correspondence, the lack of support at the MC for the revisions underscores the need for PJM to have the ability to operate independently from its membership when necessary.

Stern added that comments stakeholders made prior to the MC vote showed a mistaken belief that the membership, rather than PJM, has public utility rights and responsibilities to control regional planning. He said that is not the case under the status quo and creates a dynamic where PJM is responsible for planning a reliable grid without having the needed control over how it conducts that planning.

“With generation deactivations accelerating, energy demands increasing and a portfolio of new generation waiting to interconnect, PJM’s ability to ensure future reliability and affordability for customers is critical and would be enhanced by PJM having the ability to bring critical regional transmission planning issues to the Commission at the time it believes appropriate and as intended when PJM was formed,” Stern said.

Stern said there have been several efforts to expand PJM’s planning processes in the past that have been stymied by deadlocks in the stakeholder process, including establishing a paradigm for storage as a transmission asset (SATA), as well as efforts to enhance interregional planning. (See Vote Delayed on PJM SATA Proposal)

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New England Stakeholders Talk Community Engagement at Roundtable

BOSTON — Early and meaningful engagement with host communities will be an essential component of expediting energy permitting and siting processes, panelists said at Raab Associates’ New England Electricity Restructuring Roundtable on June 14. 

“We are in a change-or-die moment,” said the Rev. Mariama White-Hammond, former chief of energy, environment and open space for the city of Boston, adding that the pace of clean energy deployment must accelerate rapidly to meet the need to decarbonize.  

To meet the moment, utilities and project developers will need to collaborate with many of the communities and organizations they fought in the past, she said.  

“There is a question of who will hold the power,” White-Hammond said. “Will it be the technocrats, investors and government officials, or will it be all of us?” 

Ultimately, developers will face significant backlash if they try to force through projects without incorporating community input in the decision-making process, White-Hammond added. 

Penni McLean-Conner of Eversource Energy echoed the need to work with communities in the early stages of project development and consider community input when weighing the tradeoffs of project alternatives. 

“Eversource is committed to an enhanced community-centric approach,” McLean-Conner said, adding that the company hopes new energy facilities can be seen as opportunities rather than burdens by residents. 

One key to changing this conversation is understanding and respecting the historical inequities faced by these communities, McLean-Conner added. 

“We can’t assume we know or have all the answers,” she said. “We need to incorporate their shared experiences and unique perspectives into our thinking going forward.” 

Larry Susskind, professor of urban and environmental planning at MIT, said project developers should work with a range of stakeholder representatives and organizations to reach “informed consensus” within a “confidential space for joint fact-finding and collaborative problem-solving.” 

Once developers identify the unique needs and concerns of a host community, they should negotiate and sign binding community benefit agreements they submit to the state during the permitting process, Susskind said. 

Getting community benefit agreements right is “as much about compensation as it is about mitigation,” Susskind said, adding that “we need to think in terms of bartering to create benefits, not just minimizing costs.” 

Permitting and siting has been a major topic of conversation for Massachusetts lawmakers over the past few months, with key legislators indicating it’s a top priority for a potential climate bill they hope to pass by the end of the current session in July. 

Legislative leaders of the House and Senate have been working with the Healey administration to develop a compromise bill that likely will revolve around the recent recommendations of the state’s Commission on Energy Infrastructure Siting and Permitting. (See Mass. Commission Issues Recs on Energy Project Siting, Permitting.) 

The Massachusetts Senate plans to take up a climate bill centered around permitting and siting reform this week.  

The state commission recommended consolidating state and local permitting and siting processes and requiring authorities to issue permits within 15 months of verifying that an application is complete.  

Michael Judge, undersecretary of energy at the Massachusetts Office of Energy and Environmental Affairs, said the state’s Energy Facilities Siting Board (EFSB) historically has taken between one and four years to approve a project, “after which the project still needs to get all other permits.” 

“This isn’t working for anyone,” Judge said, adding the state is unlikely to meet its climate mandates without permitting reform.  

Adam Chapdelaine, CEO of the Massachusetts Municipal Association, which represents the state’s 351 cities and towns, expressed his “concern about getting consolidated permitting right” while preserving the rights and role of municipalities. 

He recommended initially adopting an opt-in consolidated local permitting program to inform the consideration of statewide reforms to local permitting. 

In response, Judge emphasized that, under the commission’s proposal, local permitting would remain under local control but would need to be expedited and consolidated under one permit parallel to the EFSB approval process.  

He said making the local permitting reforms optional could lead to an “inconsistent framework” for smaller projects that are subject only to local permitting, potentially creating longer timelines for some smaller projects.  

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Counterflow: Fusion is Getting Increasing Attention

2024 is the 35th anniversary of the discovery of cold fusion! 

OK, just kidding. 

Back to reality: Renewable resources generally are not dispatchable. We are searching high and low for an economic solution to this problem because dispatchable resources like coal and natural gas emit carbon.  

Certainly it is wise to maintain existing nuclear plants, as I urged long before it became fashionable. But other resources remain highly problematic.  

New nuclear fission, such as small modular reactors, has a very high cost. Although a recent Atlantic article says we should take a leap of faith because failure is not an option (citing the siting challenges of large wind, solar and transmission), hope is not a plan. 

Long-duration battery storage is extremely costly, as I discussed in my most recent column. Green hydrogen electricity is a pipe dream (no pun intended), as I discussed before. 

The Fusion Revival

Fusion is getting increasing attention as a possible salvation. 

I’m here to tell you that commercial fusion is another fantasy. 

The old saying is that commercial fusion is 30 years away and always will be.1 An Oak Ridge director of fusion energy research said at a conference: “The projected time to realize the ultimate goal of commercial fusion always seems to be 25 or 30 years away.” He said that in 1986 — 38 years ago. So even then it was a cliché. 

‘Net Energy’

But the hoopla continues, most recently about “net energy” being generated in fusion tests (for example).

Two things about such tests that don’t get reported in the media: first, that the amount of energy generated is trivial. The most energy generated in a fusion test, at the U.K.’s Joint European Torus (JET), is 69 megajoules. That sounds like a lot, but it is the equivalent of 19 kWh. Basically, it could power one American household for about two days. (The monthly average is 900 kWh.) 

Second, this isn’t really net energy. When the JET was running, it consumed 700 to 800 MW (yes, megawatts). 

As for the 3.88 megajoules generated at the U.S. National Ignition Facility, the claim is made of “net energy” because 3.88 megajoules generated are more than 2.05 megajoules “delivered to the target.” The net of 1.83 megajoules would power a 100-W lightbulb for all of five hours. 

But more importantly, this formulation ignores the 322 megajoules it took to power the 192 lasers to “deliver” the 2.05 megajoules.2 It’s not “net energy” — it’s negative energy. The ratio of energy consumed to energy generated is about 83 to 1.  

Reality Check from a Retired Nuclear Fusion Physicist

Part of the problem with fusion is that we’ve spent $100 billion on it, and thereby created an industry dependent on huge taxpayer subsidies and on hoopla to keep those subsidies coming. Experts not dependent one way or another on the public’s money are few and far between. 

But I did find this sobering analysis by a nuclear fusion physicist who worked on nuclear fusion experiments for 25 years at the Princeton Plasma Physics Lab in New Jersey, and who is … retired.3 Here are some of his key points: 

    • huge parasitic power consumption 
    • tritium fuel not fully replenished 
    • radiation damage and radioactie waste
    • nuclear weapons proliferation 
    • outsized operating costs.

His follow-up article focused on the colossal International Thermonuclear Experimental Reactor (ITER) in France, originally scheduled to test its “first plasma” in 2020 and achieve full fusion by 2023. However, the schedule was pushed back to test first plasma in 2025 and achieve full fusion in 2035, and now the schedule is … nobody knows. The ITER has been portrayed repeatedly as using 50 MW to generate 500 MW, but the reality is that it will use 300 MW to generate 0 MW of electric energy. 

If, after reading his analyses, you still think there’s a realistic future for commercial fusion, then I admire your optimism. And there are three dozen fusion startups that might welcome your investment dollars. 

Path Forward

The fact remains we have no realistic, affordable way to maintain resource adequacy in a net-zero future other than to keep a fleet of natural gas plants around that can be dispatched as needed — maybe not many hours a year, but enough. This will vary across regions. And they’ll have to be compensated to be available and flexible as needed. In the organized markets, they’ll have to get meaningful capacity payments to stick around. In the cost-of-service states, they’ll have to get regulated compensation. The carbon emissions of the gas plants can be offset/captured as different states deem worthwhile. 

This is not rocket science.  

Speaking of rocket science, let me repeat from a couple recent columns4 that regardless of what we might do here and in Europe, humanity as a whole is gonna need Plan B: solar geoengineering. There is no realistic alternative, at least for the near and medium terms (until perhaps those 30 years for commercial fusion to become reality). 

“We all have to take a chance. Especially if one is all you have.” — Capt. James T. Kirk, “Tomorrow Is Yesterday,” 1967. 

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years. 

 

 

1 A collection of articles about fusion spanning decades as published by the Bulletin of the Atomic Scientists is here: https://thebulletin.org/collections/fusion-energy/

2 https://www.scientificamerican.com/article/nuclear-fusion-lab-achieves-ignition-what-does-it-mean/ (“NIF’s 192 lasers consumed 322 megajoules of energy in the process.”)
https://pubs.aip.org/physicstoday/online/42581/National-Ignition-Facility-earns-its-name-for-a https://www.vice.com/en/article/xgwpkk/jet-reactor-fusion-energy-record-setting-breakthrough

3 https://thebulletin.org/2017/04/fusion-reactors-not-what-theyre-cracked-up-to-be/#post-heading. An interesting and very readable anonymous posting by an electrical engineer in the industry is here, https://www.reddit.com/r/fusion/comments/10buldl/what_are_the_biggest_hurdles_facing_companies/

4 https://energy-counsel.com/wp-content/uploads/2023/08/World-of-Hurt.pdf; https://energy-counsel.com/wpcontent/uploads/2022/05/We-are-Going-to-Need-a-Plan-B-RTO-Insider-5-10-22.pdf A recent Economist article on the Antarctic ice melt also sounds the alarm, https://www.economist.com/interactive/science-andtechnology/2024/03/27/antarctica-earths-largest-refrigerator-is-defrosting

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Calif. Clean Transportation Program Needs Equity Emphasis

California’s funding of zero-emission vehicle (ZEV) infrastructure must be more equitably allocated to disadvantaged communities, according to advisory committee members for the state Energy Commission’s (CEC) Clean Transportation Program Investment Plan.  

“We have the highest prevalence of asthma in Imperial County in comparison to the rest of the state of California and the rest of the nation. … From the moment we arrive here, we are persistently assaulted … with carcinogens and irritants that are causing respiratory problems and cancer,” committee member Luis Olmedo, executive director of the nonprofit Comite Civico del Valle, told NetZero Insider. “For that reason, it is extremely important that we transition to net-zero transportation and the net-zero economy as swiftly and as quickly as we possibly can.”  

Details of the Clean Transportation Program were discussed at a June 7 meeting hosted by the CEC, where industry experts grappled with how best to spend the almost $100 million available annually.  

“How do we spend our money wisely to accelerate zero-emission transportation and do it in a way that’s very attentive to equity?” CEC Commissioner Patty Monahan said at the meeting. “We need to ensure that Californians who are too often left behind in the transition to clean energy and left behind in terms of facing disproportionate burdens of air pollution, we need to make sure those communities benefit.” 

Established in 2008 and recently extended through July 2035 under Assembly Bill 126, the Clean Transportation Program promotes accelerated development and deployment of ZEVs and related infrastructure to meet California’s goal of electrifying 100% of passenger vehicles and drayage trucks by 2035 and 100% for medium- and heavy-duty trucks by 2045. It receives an annual investment of up to $100 million using funds collected from vehicle and vessel registration, license plate and smog abatement fees.  

Through 2023, the program was responsible for installing or planning more than 33,300 chargers for ZEVs, creating block grants to incentivize light-duty EV charging infrastructure projects, and allocating funding for 96 publicly available hydrogen fueling stations. It also awarded more than $107.4 million in ZEV infrastructure incentives to 190 projects through the nation’s first commercial vehicle fleet incentive project, called Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles, and more.  

The CEC provides an annual investment plan update that guides the allocation of program funding for transportation solicitations for the upcoming fiscal year. Proposed investments for 2024/25 totaled $1.52 billion with the addition of National Electric Vehicle Infrastructure program funds, according to Benjamin Tuggy, Clean Transportation Program Investment Plan project manager at the CEC. Of that total, $656 million is allocated to light-duty charging infrastructure, $810 million to medium- and heavy-duty charging, $46 million to “emerging opportunities” and $3 million to ZEV workforce development.  

The CEC requires that more than 50% of funds go to projects that benefit low-income or disadvantaged communities. The Communities in Charge program, which is run by CALSTART and deploys Level 2 chargers, provided $68 million over two funding windows, all of which went to projects in disadvantaged communities, Marissa Williams, a supervisor in the CEC’s Fuels and Transportation Division, said during the meeting.  

Additionally, the CALeVIP 2.0 program, which is administered by the Center for Sustainable Energy and deploys DC fast chargers, also distributed $68 million, with a requirement that all projects be in disadvantaged communities.  

‘Equity Equals Capital’

But despite the emphasis on equity, some advisory committee members said disadvantaged communities still weren’t being adequately considered. Olmedo told NetZero Insider that while funding is being allocated to low-income communities, it often goes to those in metropolitan areas “where the market is,” creating EV deserts in rural communities like his own.  

“We have a lot of EV deserts in California. Companies aren’t going to go and invest there because the market isn’t there,” Olmedo said at the meeting. “The other thing that makes it even more challenging is when you have other state agencies like GO-Biz [Governor’s Office of Business and Economic Development] directing developers to go where the market is and specifically where they have adopted a streamlined permitting process. So, these programs are working against each other to continue to make it more difficult for these EV deserts to thrive.”  

Olmedo pointed to legislation that requires permitting agencies to develop a streamlining mechanism, saying it is well intentioned but creates unintended barriers for low-income communities that may not have an internal permitting agency or the staff and resources required. GO-Biz created a map that shows which cities have streamlined permitting processes, signaling developers to “go there,” Olmedo said. 

“That communication is what we characterize as redlining in our communities, making it harder when you’re signaling to developers not to come here. You’re creating an EV desert” he said. “There’s a lot of times a misalignment in communication between the Energy Commission, who’s like ‘Hey, let’s build, build, build,’ and then GO-Biz … saying, ‘Yes, build, but build over there.’ So, that became very problematic.” 

In an interview with NetZero Insider, advisory committee member Rev. Dr. Charles Dorsey described how state efforts to distribute funding for clean transportation or other resources don’t adequately consider disadvantaged communities. In particular, he pointed to problems with the state’s processes around requests for proposals, which pit disadvantaged communities against bigger organizations that have won awards in the past.  

“The structure and the requirements of the proposal automatically create barriers for companies that are led by people of color,” he said. “You have a limited number of contractors who can actually equitably apply.”  

“They believe that just by putting the proposal out, that it is equal competition. It is not. Because they designed the proposal without considering the barriers that are already in place,” Dorsey said.   

Both Olmedo and Dorsey think the state should better address inequities built into its processes. Olmedo emphasized the importance of including more nonprofits in the process instead of prioritizing for-profit companies that can make money quicker. He noted at the meeting that Comite Civico Del Valle was one of the first nonprofits to receive funding from the CALeVIP 2.0 grant program, which says “a lot about how the state has been wrong in how it has prioritized its investment.”  

“If you go to rural communities, you’re not going to make a profit in the next three years,” he said. First, you [have to] create reliable EV infrastructure, and then disadvantaged, low-income communities can take the risk of buying an electric vehicle. Because you have less income, you can’t risk not having reliable infrastructure, because that might mean you don’t get to work on time. That might mean that by the end of the day, you don’t have a job.”  

Collaborating with nonprofits and investing in a three-to-five-year plan can create a market in rural communities that ultimately will help California meet its decarbonization goals, Olmedo said. He’s optimistic the Clean Transportation Program will bring EV infrastructure to rural, disadvantaged areas, as long as enough money is invested.   

“What we need is capital, and we need to make that a commonly used term whenever we talk about disadvantaged communities,” Olmedo said in the meeting. “Don’t give us more paper. Don’t give us more education. Yes, that is necessary, but equity equals capital, and these programs need to be designed to bring equity and capital into these rural clean transportation deserts.”  

While many advisory committee members at the meeting said the allocation of the $1.52 billion was appropriate, Dorsey emphasized he won’t know until there’s a formal process in place to overcome investment barriers for disadvantaged communities.  

“When you ask me if the spread is right, you’re also asking me if the process is right,” Dorsey said. “And I can’t answer that question.” 

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Stakeholder Soapbox: A New Twist on Capacity Markets in Japan

Reliability is a global problem that requires local solutions. For more than 15 years, PJM’s solution has been its forward-looking capacity market, the Reliability Pricing Model. Meanwhile, on the other side of the world, Japan recently enacted major reforms to its energy system. Those reforms have included a PJM-inspired capacity auction first held in 2020 for the 2024 delivery year and a related long-term decarbonized power resource auction inaugurated this year. 

Japan’s energy reforms are of increasing importance globally, including to U.S. companies and investors. A weak yen has spurred investment in Japanese energy projects, and foreign- and U.S.-owned energy companies have started winning major capacity contracts in Japan’s new system. Recent developments in Japan have revealed, however, that its market differs in significant ways from those in the U.S. — including from the very PJM capacity market on which Japan modeled its own. 

A Modified PJM Capacity Market in Japan

When Japan embarked on its energy reforms, it formed a study group to examine foreign capacity markets, including PJM’s, and to make a proposal for how best to ensure long- and midterm reliability in its energy markets. Ultimately, the study group concluded a capacity market similar to PJM’s model (and the model used in the U.K.) would work best. 

The capacity market system Japan ultimately adopted shares the same basic structure as PJM’s. It is presided over by a private transmission organization called the Organization for Cross-Regional Coordination of Transmission Operators (OCCTO). Like PJM, OCCTO runs a centralized capacity auction where generation resources offer to sell capacity for a price, and the auction’s clearing price is ultimately set at the point where supply and demand curves cross. 

There are, however, several key differences between Japan’s market and PJM’s. For example, unlike PJM’s system, participation in OCCTO’s capacity market is never required for participation in Japan’s wholesale electricity markets.  And unlike PJM, OCCTO does not administer the wholesale electricity market itself: Another organization, the Japan Electric Power Exchange, does. 

Perhaps most critically, OCCTO’s and PJM’s systems are different because they are governed by different legal frameworks. OCCTO is authorized and governed by Japan’s 2015 amended Electricity Business Act, while PJM (like other U.S. RTOs) is governed by the Federal Power Act. Those laws impose materially different restrictions, based on different national policies. The FPA, for example, embraces what U.S. courts have long called the filed-rate doctrine, which forbids retroactive rate changes. That prioritizes pricing predictability, even when doing so may result in higher-than-necessary consumer prices. Japan, by contrast, has not adopted the filed-rate doctrine; it has prioritized lowering consumer prices instead. 

A Focus on Reducing Prices

Japan’s focus on reducing prices has been especially clear in its management of its new capacity markets. Since the first capacity auction in 2020 yielded prices far higher than expected, Japan’s energy regulator — the Electricity and Gas Market Surveillance Commission (EGC) — has been on the lookout for ways to ensure that OCCTO’s capacity auction prices remain as low as possible. That has been especially clear in the EGC’s handling of the 2022 capacity auction for the 2026 delivery year. 

First, after the 2022 auction closed but before results were announced, the EGC discovered that one capacity supplier’s offer was too high because of a mistake. In consultation with OCCTO, the commission took the unprecedented step — one that no statute or auction rule permitted — of requiring that the offer be corrected and the resulting capacity price for all participants be changed accordingly. 

Second, this year, the EGC discovered another “misbidding” mistake — this time, after the 2022 auction results had been announced and the supplier had been awarded a contract. The commission and OCCTO promptly announced that they would amend the supplier’s contract to reduce the contracted capacity price. Recognizing that such a change was also unprecedented, the organizations emphasized that such an adjustment should be made only when the resulting capacity price would be lower, to protect consumers. 

Will Japan Adopt Something Like the Filed-rate Doctrine?

Japan’s energy and capacity markets are, in many ways, still in their infancy. Japan might still develop or adopt something akin to the filed-rate doctrine, or it might reject the doctrine expressly. Either way, Japan cannot help but recognize that market forces demand some degree of pricing predictability. Even in the recent misbidding investigations, for example, Japanese regulators showed they are sensitive to the same concerns that motivate the filed-rate doctrine. They could have undone the entire 2022 capacity auction this year after they discovered that misbidding affected the clearing price, but they did not. Instead, they amended only the responsible supplier’s contract while recognizing that amending such established contracts should be a rare event — one limited to situations where it will protect consumers without destabilizing market expectations. 

Even without a formal filed-rate doctrine, in other words, Japan’s capacity markets are not the Wild West. Japan cannot make reneging on capacity prices a habit, because participation in the capacity markets there is entirely voluntary. To incentivize participation and ensure reliability for consumers, if nothing else, Japan will need to safeguard the predictability of prices once they are set. Whether it will formally adopt the filed-rate doctrine, or something like it, in the years to come remains to be seen. 

 

Eri Akiyama is an attorney with Nagashima Ohno & Tsunematsu with a practice that includes energy and other complex civil litigation. She served as an international associate at MoloLamken LLP in New York from September 2023 to June 2024. 

Jennifer Fischell is a partner at MoloLamken with a practice focusing on energy and complex civil litigation, administrative law and appeals. She has clerked for judges at all levels of the federal judiciary, most recently for U.S. Supreme Court Justice Elena Kagan.