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December 22, 2024

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FERC Approves JTIQ Framework, Cost Allocation

FERC on Nov. 13 approved tariff revisions and modifications to the joint operating agreement between MISO and SPP that will enshrine a structural and cost-allocation framework for the five 345-kV projects in the RTOs’ $1.6 billion Joint Targeted Interconnection Queue (JTIQ) portfolio (ER24-2798, ER24-2825). 

In a 4-0 decision (in which Commissioner Judy Chang did not participate), the commission found the proposed revisions to the RTOs’ generator interconnection processes and pro forma GI agreements in their respective tariffs and Joint Operating Agreement complied with its rules “by helping to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.” 

FERC said the proposed allocation of 100% of the JTIQ portfolio’s cost to interconnection customers is consistent with the cost-causation principle and allocates costs at least roughly commensurate with estimated benefits. The commission said the JTIQ study addressed transmission system limits preventing the interconnection of future generation capacity, thus benefiting all interconnection customers. 

“Interconnection customers are the primary beneficiaries of the JTIQ upgrades, and therefore the proposed allocation of 100% of the capital costs … to interconnection customers when fully subscribed is just and reasonable,” FERC said. “The RTOs also have shown that the JTIQ upgrades do not provide sufficient benefits for load in either RTO to qualify as transmission projects selected in the regional transmission plan for purposes of cost allocation.” 

MISO and SPP will now take the JTIQ portfolio to their respective boards’ upcoming meetings for their approval. Both boards meet in December. 

The RTOs expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to offset about 25% of the portfolio’s capital costs. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.) 

Commissioner Mark Christie wrote a concurring opinion, noting that the JTIQ projects would not have been selected in the RTOs’ regional transmission plans. 

“These projects are not designed to serve load, i.e., consumers, with optimal solutions to identified reliability concerns or economic drivers,” he wrote. “Rather, the primary purpose of these projects is to provide interconnection customers — generation developers, primarily wind and solar — with more interconnection opportunities. Accordingly, it is appropriate that the primary funding for these projects is from the generation developers themselves, as they are the primary beneficiaries.” 

Christie said the order establishes that the benefits to load meet the cost-causation principle, justifying the RTOs’ proposal that load provide backstop funding for the portfolio. He said the funding mechanism is only just and reasonable with the GRIP funding covering 25% of the capital costs. 

“Without this funding, it would be unjust and unreasonable to allocate to load any of the [portfolio’s] costs,” he said. “These projects were not designed to serve load, plain and simple, and if there were no funding, the JTIQ proposal would not be acceptable.” 

Aubrey Johnson, MISO’s vice president of system resource planning and competitive transmission, said in an email and on social media that the JTIQ is a “critical process” to add more generation. 

“It provides certainty to interconnection customers near the SPP-MISO seam and enables lower-cost energy in each region,” he said in extending his appreciation for SPP’s “strong collaboration and innovative thinking” that led to the “first-of-its-kind framework.” 

SPP’s Casey Cathey, vice president of engineering, said the grid operator is “thrilled” that FERC recognized the JTIQ’s long-term value and its future benefits to members and customers. 

“We’ve had a successful partnership with MISO for many years and look forward to building on that success with the JTIQ initiative,” he said in an email. “These transmission projects will be a significant step toward eliminating barriers and improving the efficiency and reliability of transmission between our regions.” 

The two RTOs began working on the JTIQ process in 2020 after several unsuccessful attempts to find joint projects to alleviate congestion on their seam. They conducted reliability, economic and generation-enablement studies and coordinated with stakeholders to develop transmission solutions to identify the JTIQ upgrades that unlocked generating facilities and aligned their interconnection processes to reduce restudies and delays. 

MISO and SPP say the projects, focused on their northern seam, are expected to enable 28 GW in generation additions. They said the generation projects were stymied by the massive amounts of interconnection requests; the lack of current system capacity to accommodate the requests; and the significant incremental cost of upgrades that interconnected individual clusters that would otherwise be obligated to pay for the upgrades under the RTOs’ existing “but for” cost-allocation frameworks. 

The backbone of network upgrades consists of five projects, cut down from the original seven: 

    • Bison-Hankinson-Big Stone South, 147 miles of new 345-kV lines in the Dakotas (MISO).
    • Lyons Co.-Lakefield Junction, 80 miles of new 345-kV lines in South Dakota and Minnesota (MISO).
    • Raun, a new 345/161-kV double circuit and rebuilt 161-kV lines near Omaha, Neb. (MISO, SPP).
    • Auburn-Hoyt, new 345-kV lines in Nebraska (SPP).
    • Epanding and rebuilding a 345-kV substation in Sibley, Iowa (SPP). 
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Collaboration Needed to Address Large Loads, NARUC Panelists Say

ANAHEIM, Calif. — The power industry should encourage increased collaboration and transparency to address the many challenges posed by major new loads, presenters said during the National Association of Regulatory Utility Commissioners’ Annual Meeting from Nov. 10 to 13.

Data centers, hydrogen, transportation and other industries are all contributing to the rapid load growth, which can present both efficiency opportunities and forecasting challenges, according to Natalie Mims Frick, deputy department leader of energy markets and policy at Lawrence Berkeley National Laboratory.

Providing opportunities for conversations between stakeholders can help address those challenges, Frick said. She pointed to the North Carolina Utilities Commission’s recent ruling on Duke Energy’s consolidated carbon plan and integrated resource plan. One of the requirements is that the utility must provide frequent updates on load growth, Frick said.

“Having regular conversations can be really useful about how to deal with the growth and where it’s happening,” Frick said. She added that another requirement the North Carolina commission imposed was requiring the utility to work with their large customers “to try and identify opportunities for efficiency or other resources, whether it’s flexibility or something else.”

“And I think that kind of feeds back into the loop forecasting, you know, making sure that there’s robust consideration of all of the opportunities for the large loads, whether it is through flexibility or demand response to reduce peak demand,” Frick said.

Forecasting from a data center and automation perspective will likely remain a challenge, given confidentiality around business strategies, according to Samantha Klug, enterprise sustainability development director of logistics real estate investor Prologis.

However, it would be helpful if regulators could provide a roadmap around electrification and sustainability incentives, Klug argued.

“Because then what we can do is forecast out these projects and where we want to do them based on those incentives, and when the timing for capital investment is right for us,” Klug said. “And so for us, it’s really the communication between stakeholders.”

In a separate panel discussion, Farah Mandich, presidential sustainability executive at the General Services Administration, argued that transparency is important to help “people understand why the utilities and commissioners are making some of the decisions they do.”

Mandich added that thinking about customers’ needs as an asset, instead of just a problem to solve, is a good “mindset to be in.”

“The federal government is a longstanding existing customer. We are electrifying loads, but we’re not going to be causing the type of growth that you know a data center necessarily is in one given place, but that means that our buildings could potentially be an asset for load flexibility,” Mandich said. “And so thinking about how to bring customers into that conversation up front is really important, because it’ll take us a while to figure out how to do that in our own buildings and work with the utilities effectively.”

Jeff Riles, director of energy markets at Microsoft, noted that customers, regulators and utilities are all cooperating more frequently now than a few years ago. However, he said that there are challenges, including mistrust around growth of the data center industry.

“There’s a real concern about what’s speculative and what’s real,” Riles said. “And there’s a need to make sure that we’re showing up and helping them address the problem of what is speculative and what’s real. And so that’s been another reason why we have begun to engage more directly in a lot of these regulatory proceedings.”

He added that engaging in forums like NARUC “is new for us as an industry, and so we really appreciate the opportunity to have this collaboration. But I will just say we’re growing up right along with you in terms of how we engage in these processes and procedures.”

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MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures

CARMEL, Ind. — MISO will take a breather from its long-range transmission planning over 2025 to retool the 20-year future scenarios that are the foundation of the transmission portfolios.  

Speaking at a Nov. 13 Planning Advisory Committee meeting, MISO’s Jeremiah Doner said after consultation with stakeholders, MISO will concentrate on a futures makeover throughout 2025. MISO maintains three possible futures scenarios in Goldilocks style: a conservative view of the system with limited load growth and decarbonization, a middle-of-the-road view, and a progressive outlook where clean energy, innovation and demand thrive. 

Some MISO stakeholders have said repeatedly the rate of change the three planning futures predict is obsolete considering that clean energy goals are revised frequently to be more aggressive and load additions are rising. MISO last overhauled its futures in 2019 and refreshed them in 2022. 

MISO said it won’t embark on another long-range transmission plan (LRTP) analysis until 2026, when the RTO will work on a follow-up portfolio to the second Midwestern LRTP portfolio. That would leave MISO South’s comprehensive planning needs unaddressed until at least 2027.  

Doner said MISO’s futures update will kick off unofficially with the RTO’s Dec. 18 stakeholder workshop on medium- and long-term load forecasting, where it plans to discuss probable load increases over the next 20 years. 

“Let’s get through the futures update, and this time next year, we’ll have better answers” on when the Midwest follow-up portfolio and a third LRTP portfolio will take place, Doner said.  

“One thing we want to do with the futures update is to make sure it serves multiple masters,” Executive Director of Transmission Planning Laura Rauch said, adding that discussion on the futures revision would start in workshops, and likely in Planning Advisory Committee and Resource Adequacy Subcommittee meetings.  

The Organization of MISO States lent support to the futures revision, though it emphasized the “importance of improving connections between Midwest and South and needs within South region.”  

Some of the regulators in the Organization of MISO States have asked what MISO plans to do about MISO South planning in the meantime. Illinois Commerce Commissioner Michael Carrigan pointed out at a Nov. 11 OMS board meeting that MISO’s LRTP timeline seems to leave MISO South without an economic planning study for about six years.  

The working group of the Entergy Regional State Committee also recently asked MISO to perform a market congestion planning study for the MISO South region as part of MISO’s 2025 Transmission Expansion Plan (MTEP 25). So far, the RTO hasn’t added an economic study to its MTEP 25 tasks.  

Doner said in addition to the futures renovation and usual MTEP 25 studies next year, MISO would like to examine how it can address large load additions in planning, focus on its current interregional planning studies with PJM and SPP and make sure it’s ready for compliance under FERC Order 1920.  

Doner said MISO also has to devote staff hours to making sure approved LRTP projects are best positioned to advance through state permitting processes.  

“Even though [LRTP] Tranche 1 was approved two years ago, there’s work to support [these projects] in regulatory processes. Until those projects are certain, there’s still some risk there,” Doner said.  

Finally, Doner said MISO will work on planning coordination with neighbor Associated Electric Cooperative Inc. (AECI) over next year. He said AECI has planned projects that will tie into Ameren and SPP’s territories and the cooperative has approached MISO for some advice on how best to proceed.  

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MISO Says Comfortable Wintertime Margins Likely in Store

MISO does not foresee a scenario where it comes close to risky operations this winter, saying even a 107-GW demand peak should be manageable without emergency protocols. 

The grid operator published its annual winter outlook this week, predicting a nearly 21-GW excess in cleared capacity December through February using a coincident peak forecast and normal generation outages. Beyond its traditional supply, MISO has about 12 GW in load-modifying resources and operating reserves to lean on. 

At a Nov. 14 workshop to discuss results, resource adequacy engineer John DiBasilio said that though MISO’s capacity auction cleared 121.6 GW of traditional generation for the winter, offers totaled 137.4 GW. 

Across the board, MISO’s load-serving entities predict a 100.1-GW coincident peak; however, LSEs’ non-coincident peak predictions are 101.9 GW in December, 107 GW in January and 101.5 GW in February. Should a 107-GW peak occur in January, the RTO still predicts a 14.6-GW surplus among its nonemergency supply. 

In a press release, Executive Director of Market Operations J.T. Smith credited MISO’s relatively new seasonal capacity auction for better preparing the footprint. 

Last winter, MISO managed a 106-GW peak Jan. 17 during a wide-reaching cold spell without resorting to emergency procedures. (See MISO Holds Steady in Mid-Jan. Storm with Help from Wind.) MISO experienced its 109-GW all-time winter demand record on Jan. 6, 2017. 

Part of MISO’s anticipated capacity sufficiency this winter is also thanks to an anticipated warmer winter across the footprint. 

Analytics company and weather forecaster DTN predicts above-normal temperatures for the season in MISO’s South and Central regions with slightly warmer or closer-to-normal temperatures in the North region. The RTO splits its Midwest region into the Central, which includes the Dakotas, Minnesota, Iowa and Montana, and the North, which includes Wisconsin, Michigan, Illinois, Indiana, Missouri and Kentucky. 

The National Oceanic and Atmospheric Administration anticipates closer-to-normal temperatures for MISO Midwest and a winter that trends above normal in MISO South.  

Both forecasting authorities call for above-normal precipitation in MISO Midwest, especially around the Great Lakes, and a drier season for MISO South. MISO said the expected below-normal precipitation should decrease generation icing risks across the South. 

MISO’s in-house meteorologist, Brett Edwards, said the season will be similar to last winter, which saw “exceptionally warm” temperatures, except for the mid-January cold snap, and normal precipitation patterns. The grid operator said last year’s temperatures are not a reference point for the upcoming winter. 

Edwards said the best chances for some frigid days in MISO Midwest come in December and February if a weaker La Niña prevails. If a moderate-to-strong La Niña occurs, warmer air is expected to spread farther north. Edwards said the climate pattern appears to be shaping up to be weaker. He said historically, “weaker La Niña events have generated some cold shots and heavier precipitation events for the Midwest.” 

MISO meteorologist Adam Simkowski added that though the RTO is anticipating a warmer winter overall, it is not ruling out the possibility of a few frigid blasts that drive load up, even in the South. He said that an active storm pattern around the Great Lakes could increase generation icing risks. 

The RTO also noted that if all goes well at FERC, it should have an agreement on emergency energy purchases in place with the Tennessee Valley Authority beginning Dec. 24. (See MISO and TVA Strike Emergency Energy Purchase Agreement, Request FERC OK.) 

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Stakeholder Soapbox: Kill Subsidized Energy Efficiency for the Public Good

By Kenneth W. Costello

Ken Costello |

Many state utility regulators, policymakers, utilities and others construct the orthodox, and politically palatable, argument that market failure justifies utility energy efficiency (EE) programs and that the vast majority of those programs would pass a cost-benefit test. 

Electric and natural gas utilities together spend about $10 billion annually on energy efficiency. This is in addition to the billions of dollars the federal government spends, boosted substantially by the Inflation Reduction Act (e.g., an expansion of tax incentives for the installation of energy-efficient building upgrades and the construction of energy-efficient homes). Besides all of this, subsidized EE is a major component of state and federal governments’ energy policies, driven in recent years by efforts to combat climate change.  

Using the label “no-regrets,” policymakers frequently push actions they endorse as unequivocally good —everyone wins, no one loses. The “free lunches” that EE advocates ascribe to EE programs should therefore seem suspicious to anyone after little thought. 

They certainly do to many analysts who have seriously studied the benefits and costs of EE initiatives. If these efforts are such a good deal, then why must government mandate or utilities subsidize them? Why aren’t energy consumers taking advantage of the large benefits that EE supposedly offers them? Are they that irrational and unaware of the benefits from EE to warrant subsidies or mandates; or, more accurately, do consumers just find better ways to invest their limited monies? It may very well be that energy consumers prefer to invest in other things, like home repairs, a new car or college. And it’s not because of market failure. 

I am skeptical for two basic reasons. First, the idea that markets are less than perfect should not infer that intervention in the form of utility subsidies or government mandates benefits society. One of the major errors with government actions in a wide array of areas starts with the premise that since markets aren’t perfect, the government should intervene. This more times than not results in a higher cost to society than the benefits received. There is a concept that is often ignored in public policy debate: “government failure.” 

One glaring problem is that ostensibly objective analysis of specific EE initiatives often reaches different conclusions from evaluations prepared either by utilities or for utilities. 

Why is this, and whose results are more credible? Most utilities or their evaluators fail to apply the best analytical tools to their evaluations of EE programs. These tools include randomized trials and quasi-experimental designs to measure energy savings and account for consumer behavior. The problem with other approaches is that they are unreliable — in some instances grossly flawed — in measuring the actual energy savings from individual EE programs. 

Another evident reality is that utilities have a self-interest in portraying their EE programs as cost-effective and, therefore, worthy of favorable treatment by their regulator (e.g., allowing the utility to profit). We cannot forget that regulators and policymakers themselves receive kudos from the public for supporting subsidies whose intent is to tackle climate change, in addition to promising reduced utility bills. 

Going back, academic reviews of EE programs conclude that such programs are not the “low-hanging” fruit many people believe. They show that utilities grossly overstate energy savings from EE programs because they rely on engineering estimates that fail to account for consumer behavior (the so-called “rebound effect” or price-elasticity effect) in using, say, their higher energy-efficient air conditioners and heating systems more intensively because of lower operating costs. 

Studies also find “free riders” participating in EE programs. These are individuals who would have purchased lower-energy-use appliances or heating and air conditioning systems in the absence of the EE program.  It would be wrong to count their energy savings as real benefits, which can show a program as cost effective when in fact it is not. Some studies have shown that participants in utility EE programs primarily are consumers who are wealthier, own their own homes, and are more informed about and attentive to energy costs. 

Studies also note that government and utilities often fail to consider “hidden costs” for consumers from the time and effort spent on both energy audits and investments. The combination of these factors, according to some academic studies, has understated the true costs of EE programs by as much as 50% or more. 

Policymakers should ask the fundamental question: Why should utilities and the government subsidize EE when energy consumers are capable of making rational decisions for themselves? Is it equitable and good public policy to compel utility customers to pay for EE initiatives that benefit a relative few (who are on average wealthier than the funders of those initiatives) when some of those would have invested in EE without utility assistance? 

Kenneth W. Costello is a regulatory economist and independent consultant. 

Stakeholder Soapbox submission guidelines. 

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NERC Standards Committee Briefs: Nov. 13, 2024

In a teleconference that Chair Todd Bennett, of Associated Electric Cooperative Inc., acknowledged was “heavy with content,” NERC’s Standards Committee agreed to move forward on a number of standards development projects Nov. 13 amid sometimes lively discussions.

Changes to SAR Revision Approved

The agenda began with a proposal to revise a standard authorization request (SAR) intended to address reliability risks in the performance of inverter-based resources (IBRs). The SAR was developed by NERC’s Inverter-Based Resource Performance Subcommittee (IRPS) and endorsed by the ERO’s Reliability and Security Technical Committee (RSTC) at its last meeting Sept. 11. (See NERC RSTC Approves Charter Revisions.)

As drafted by the IRPS, the SAR would update the existing standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to require transmission owners to establish IBR performance requirements along with their associated transmission planners and planning coordinators. SC members were asked to accept the SAR, authorize posting it for a 30-day informal comment period and assign it to the standard development team for the ongoing Project 2022-04 (EMT Modeling).

Members generally expressed support for the SAR, although Amy Casuscelli of Xcel Energy asked why NERC staff proposed assigning the SAR to the Project 2022-04 team rather than Project 2023-05 (Modifications to FAC-001 and FAC-002), which is already working on the same standards. NERC Manager of Standards Development Alison Oswald explained that staff “felt that this [task] better aligned with the work that the 2022-04 team was already doing.” In addition, she said that Project 2023-05 is considered “low priority” by NERC, so its team has not met recently.

Following this exchange, Casuscelli moved that the proposed informal comment period be changed to a formal one. She explained that she was concerned that the SAR had not received wide support from the RSTC and noted that even at the IRPS meeting that approved it, only 11 of 40 members voted in favor.

“That, to me, does not read like consensus,” Casuscelli said. Her fellow members agreed to accept her modification to the proposal and passed it unanimously.

Approved Standard to be Updated

Next was a proposed correction related to the draft standard TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) and its implementation plan, which recently received industry approval in a third formal comment and ballot period that ended Nov. 4.

TOP-003-7 received a 92.77% segment-weighted approval, with the accompanying standard BAL-007-1 (Energy reliability assessments) receiving 81.53%. Both exceeded the two-thirds majority needed to move to NERC’s Board of Trustees for approval.

According to ISO-NE’s Mike Knowland — a member of the team that developed the standards — two errors were identified during the public comment period. NERC staff considered the issue urgent enough to request as part of the consent agenda that SC members waive the normal five business day limit for agenda changes.

The first error involved the effective dates for the terms “energy reliability assessment” and “near-term energy reliability assessment.” According to the balloted proposal, the terms would become effective at the same time as BAL-007-1, 24 months after the date of the standard’s approval by FERC.

However, the terms are also used in TOP-003-7, which would become effective six months before the other standard, according to the proposed implementation plan. This would mean TOP-003-7 would become effective before the definition was officially entered into NERC’s Glossary of Terms.

NERC staff proposed amending the implementation plan to move the effective date of the definitions forward by six months. In addition, staff proposed removing the term “energy reliability assurance” from TOP-003-7. Knowland explained that this term was erroneously left in the standard from a previous draft and should have been deleted before the ballot was conducted.

Committee members approved both proposals with no votes against them, although Marty Hostler of the Northern California Power Agency and Maggy Powell of Amazon Web Services both abstained, citing discomfort with the idea of changing an implementation date that industry already approved without giving stakeholders another chance to weigh in.

Because the updates are considered non-substantial, no further ballot period is required. The standards and implementation plan will be submitted to the board with the changes applied.

Next Phase of IBR Effort Underway

From there, the committee moved to three SARs concerning FERC Order 901, which requires NERC to submit new standards to improve the reliability of IBRs by 2026.

The ERO recently submitted the first of three planned tranches of new standards intended to satisfy FERC’s order. (See NERC Submits IBR Standards to FERC.) Now NERC is moving to the second tranche, which will cover data-sharing and model validation for IBRs; they are due to FERC by November 2025.

As unanimously approved by the SC members at the meeting, the SARs will be assigned to three existing standards projects:

    • Project 2022-02 — Uniform modeling framework for IBRs;
    • Project 2020-06 — Verifications of models and data for generators; and
    • Project 2021-01 — System model validation with IBRs (the new name of this project is on page 86 of the agenda but not yet on NERC’s website).

SC members also approved a proposal to appoint replacements for the chair and vice chair of the team for Project 2021-01, along with several SDT members. NERC’s Oswald explained that most of the original team members felt they lacked the expertise for their new remit. Only two of the existing team members will remain on the roster going forward, for a total team strength of six.

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CAISO Board Approves Nonprofit PTO, Tx Plan Changes

A nonprofit that wants to invest up to $1 billion in Pacific Gas and Electric’s transmission system — and to spend most of its profits on community benefit projects — has received approval to join CAISO as a participating transmission owner. 

The CAISO Board of Governors approved the application from Citizens Pacific Transmission LLC on Nov. 12.  

In other action during the meeting, the board approved modifications to two projects in CAISO’s 2021/22 transmission plan. The changes are intended to address the rapidly increasing load forecast in the San Jose area that is due partly to data centers. 

Nonprofit, Utility Partnership

Citizens Pacific is a subsidiary of Citizens Energy Corp., whose founder and chair is U.S. Rep. Joseph P. Kennedy II, son of the late U.S. Sen. Robert F. Kennedy. 

Under a partnership with PG&E, the utility will offer Citizens Pacific options to lease some of its electric transmission assets. An investment of up to $1 billion would come from five separate 30-year leases. 

Citizens Pacific plans to make an upfront rent payment to PG&E — allowing the utility to accelerate work on its transmission system. The nonprofit would recover its costs through the CAISO high-voltage transmission access charge. Citizens then would funnel profits from the arrangement into community benefit programs. 

PG&E will be responsible for the development and construction of the projects. Citizens Pacific will become a participating transmission owner after FERC approval and transfer of operational control to CAISO. 

Citizens has participated in similar partnerships with San Diego Gas & Electric. But this time, the nonprofit plans a portfolio of transmission projects rather than seeking approval for one project at a time. 

Among the nine projects are modifying 500-kV capacitors at Table Mountain and upgrading a Tesla substation. 

Neil Millar, CAISO’s vice president of infrastructure and operations planning, described the portfolio as primarily reliability-driven projects intended to meet existing and emerging load growth and bring in renewable energy from other parts of the state. 

“We applaud all efforts taken to ensure the transmission we need is built and built on a timely basis,” Millar said. 

Citizens’ past community benefit projects have included rooftop solar on the homes of low-income residents, a 39-MW community solar project in Imperial Valley, and electric vehicles and charging infrastructure for nonprofits in San Diego County such as Meals on Wheels.  

For the new set of projects, the nonprofit plans to put half its profits into community projects for the first $200 million funding tranche, increasing to 90% on the fifth and final $200 million tranche, Citizens Energy CEO Peter Smith told the CAISO board. Community benefits associated with the PG&E projects haven’t yet been determined. 

“This sure seems like a win-win,” said Board of Governors Chair Jan Schori. 

Transmission Plan Update

The CAISO board also approved modifications to the 2021/22 transmission plan involving two projects that were awarded competitively and are under development. They are a high-voltage direct current line from PG&E’s Newark substation and Silicon Valley Power’s northern receiving station (NRS) and an HVDC line between two PG&E substations: Metcalf and San Jose B. 

The modifications are needed because of load growth in the San Jose area. The 10-year load forecast for the area in the 2021/22 plan was about 2,100 MW. That has grown to 3,400 MW for a base case scenario that includes committed data center requests, according to Binaya Shrestha, CAISO’s manager of regional transmission north. Shrestha cited electric vehicle charging as another factor in the load growth. 

A sensitivity analysis that includes additional data center loads increases the forecast to 4,200 MW. 

The load growth forecast also was discussed during a Sept. 23 kickoff meeting for CAISO’s 2024/25 transmission planning process. (See Data Centers Contribute to 60% Increase in San Jose Load Forecast.) 

The approved modifications are a replacement of the HVDC line between the Newark and NRS substations with a high-capacity 230-kV AC line and a 1,000-MW rather than a 500-MW HVDC link between the Metcalf and San Jose B substations. 

Other transmission reinforcements for the San Jose area will be evaluated through the 2024/25 transmission planning process, Shrestha said. 

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FERC-State Collaborative Holds 1st Meeting on Gas-electric Coordination

FERC and a group of regulators from 10 states began discussing gas-electric coordination at the first meeting of the new Federal-State Current Issues Collaborative on Nov. 12 on the sidelines of the National Association of Regulatory Utility Commissioners’ Annual Meeting in Anaheim, Calif.

The new collaborative comes after a similar effort on transmission, which contributed to FERC Order 1920, FERC Chair Willie Phillips said at the meeting. Phillips said he was not tied to any outcome from the effort: It could lead to regulatory changes or suggestions for a legislative response.

“But I am wedded to one basic and, I think, irrefutable fact: In a nation that today is heavily invested in and dependent on natural gas as a dominant fuel in our electric supply portfolio, it is unacceptable for that fuel to not be available to meet our energy supply needs, especially during emergencies,” Phillips said.

While many disagree over the future of natural gas, the fact is that it is leading to reliability issues now and will into the foreseeable future, he added.

The issue has been kicked around for decades. (See RTOs Jointly Call for Improved Gas-electric Coordination and NAESB Forum Chairs Push for Gas Reliability Organization.)

“This forum or collaborative does not need to necessarily end with any specific action,” said North Carolina Utilities Commissioner Kimberly Duffley. “Rather, the purpose is truly discussing the current issues in a roundtable format so each of the NARUC regions and FERC can understand each other’s perspectives and positions and views, along with all of the regional differences.”

Winter storms in recent years have highlighted the risks around failing to improve coordination, which include huge costs as commodity prices spike and can lead to premature deaths when customers lose their heating at the height of winter, Duffley said.

While previous efforts have made some improvements around scheduling and opening up lines of communication between the two interdependent energy markets, they are largely siloed, said New Hampshire Public Utilities Commissioner Pradip Chattopadhyay. Ideally the end result of the task force will be to achieve “greater seamless interaction” between the two markets, he added.

One issue that has cropped up repeatedly is when cold snaps fall on long, holiday weekends, which can lead to significant issues because of the fewer opportunities to schedule delivery of fuel to generators, FERC Commissioner Judy Chang said. ISOs and RTOs increasingly factor risks on the natural gas side as they plan for and forecast reliability, she added.

While no silver bullet is going to solve the longstanding issues, Chang offered a few areas where things could improve, including information sharing and market signals to generators in restructured wholesale markets.

“The nomination process … could be better aligned between the electricity market and gas markets,” Chang said.

Many spoke about the need to expand pipeline capacity as the power sector uses more and more natural gas. But Maine Public Utilities Commission Chair Phil Bartlett said that New England has tried to do that, and it did not work out. The region’s politics also do not support major new pipelines.

“We are seriously constrained at our ability to bring in natural gas by pipeline, forcing us to rely significantly on LNG to try to get us through,” Bartlett said. “The system in New England was built largely to serve heating demand as well as to serve industrial loads. It was not designed to support gas generation, but gas generators have been able to successfully take advantage of excess capacity of the system, which exists for much of the year, most days, in order to power their operations.”

The issues come during winter cold snaps, when the pipelines are at full capacity and many of those generators cannot produce power. “If you have 10 to 14 days of really cold arctic temperatures, there’s a real concern that we’re not going to have access to the gas,” Bartlett said.

ISO-NE is working on capacity market changes that will aim to incorporate those gas constraints, which could lead to generators signing up for firmer gas supply, but Bartlett said success there was not guaranteed.

New England has been dealing with this for 20 years, as its position at the end of the pipelines and its cold winters made the issue obvious in the early days of its electric markets, ISO-NE CEO Gordon van Welie said at the Aurora Energy Transition Forum in New York in October. (See Future of Power Markets Discussed at Aurora Energy Conference.)

“I would have expected Winter Storms Uri and Elliott to have shifted the conversation. I’m shocked that it hasn’t,” van Welie said. “So, I’ve now resigned to ‘we need a 2003 blackout event’ before Congress will wake up and give somebody at the FERC, I think, responsibility for overseeing both of these networks.”

The 2003 blackout led to FERC and NERC’s reliability regime under the Energy Policy Act of 2005. Uri was responsible for hundreds of premature deaths and huge costs in February 2021, but van Welie argued it was written off as something unique to Texas, and for change to happen nationally, some major disaster needs to hit the Eastern Interconnection to move the politics of gas-electric coordination to a place where the issues will be addressed.

“We’ve got all these frictions and resistances in the system, so it’s not going to happen until something really bad happens,” van Welie said.

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RWE Pauses Investments in US Offshore Wind

RWE, which holds offshore wind leases off the Atlantic, Pacific and Gulf coasts, said it is pausing capital expenditures on development there for two years due to increased risk and uncertainty. 

The world’s second-largest wind power developer says it expects complications in the U.S. market in the wake of Donald Trump’s re-election as president.  

RWE Chief Financial Officer Michael Muller said during a Nov. 13 conference call with financial analysts that the company still sees a long-term need for offshore wind power. It still sees value in its projects, and wants to keep its options open, but it needs to be careful about its investments, he said. 

CEO Markus Krebber said: “In particular, we see higher risks and delays in U.S. offshore wind, and in the ramp-up of the hydrogen economy in our core European market.” 

RWE is developing the Canopy Wind project off the California coast and holds a lease off the Louisiana coast. It also is developing Community Offshore Wind in the New York Bight in a joint venture with Natural Grid Ventures. 

All of these projects are only in planning and are at best several years away from starting construction. But they give RWE exposure to a wide range of the technical, political and economic considerations facing the offshore wind industry as it tries to overcome recent challenges and get steel in the water in the U.S. 

With the election last week of a strident wind power opponent as president, new challenges loom. 

RWE expects its two-year pause on capital investments in U.S. offshore wind and European hydrogen projects will save it about 2 billion euros. 

Krebber said RWE is more optimistic about U.S. onshore renewables. 

The company sees very strong U.S. demand for types of power, and a particularly strong demand for green power through power purchase agreements (PPAs) — more than it can meet, in fact. 

Potential loss of the investment tax credit under the second Trump administration would not reduce the demand for new electricity, Krebber said, although it might change the economics of developing generation to meet that demand. 

Might that mean higher PPAs for RWE? The company cannot predict the future, Krebber said, as there are too many variables.

However, he said RWE has de-risked its supply chain and would undertake only de-risked investments. 

An analyst asked what impact would be felt from higher tariffs, another possibility floated by Trump.  

Krebber said RWE evaluates the supply chain risk on every U.S. project before it makes a final investment decision. And on each project, it has taken steps to protect itself, such as buying domestic products, shifting the risks onto suppliers, buying from suppliers not vulnerable to tariffs, or buying components early and stockpiling them in the United States. 

“We feel very comfortable that we can expect no negative impacts [from] very harsh measures on our projects under construction,” he said. 

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NARUC Board Passes Resolution Advancing Grid-enhancing Tech

ANAHEIM, Calif. — The National Association of Regulatory Utility Commissioners board has adopted a resolution to emphasize the role grid-enhancing technologies (GETs) and high-performance conductors (HPCs) can play in reducing customer costs and improving reliability. 

Board members passed the resolution Nov. 13 at NARUC’s annual conference in Anaheim.  

The resolution encourages Congress to appropriate more funding for programs that support GETs and HPC deployment, including two initial rounds of funding allocated to Grid Resilience and Innovation Partnerships Program grants that will benefit 29 states.  

“State regulators nationwide support using technologies to get more value out of the transmission grid,” Julia Selker, executive director of the WATT Coalition, said in a press release. “Continuing federal programs would help grid-enhancing technologies double capacity for new generation and integrate new load in the coming years.”  

GETs are another “tool in the toolbox” that can help address some of the grid’s biggest challenges — unprecedented load growth, clogged interconnection queues and rising prices — said FERC Commissioner Judy Chang during a Nov. 10 panel at the NARUC conference.  

“There are many potential benefits associated with advanced technologies and grid-enhancing technologies, and here at FERC, we’ve been really asking some of those questions,” Chang said. “What’s currently available, what’s possible in the future, what are the costs and how can grid operators and owners facilitate the use of these technologies?” 

FERC is exploring different GETs, including dynamic line ratings, advanced power flow controls and topology optimization. The commission has opened a docket looking into dynamic line ratings and is also exploring simpler solutions such as tower-lifting, which can increase the rating of the transmission line by allowing more sag and less risk.  

Many of the technologies include benefits without engaging in new transmission siting and permitting — an added benefit given the difficulty of building new transmission. 

The tools can unlock the “dynamic capabilities of the grid,” finding transmission capacity for new generation or electric demand at a lower cost than traditional upgrades. Regardless, benefits still need to be balanced with costs, Chang said.  

“What else can we do to squeeze more out of the existing infrastructure?” Chang said. “But we as regulators need to think about the balance between adopting new technology and the risk and cost to consumers associated with these things.”  

‘Remove the Disincentive’

A challenge in advancing GETs is ensuring proper and established incentives. At FERC, regulators also are grappling with whether they should incentivize or mandate new technologies. Chang said she’s cautious of mandates given the amount of information a regulator needs to establish one properly.  

“I’m a big fan of finding ways to remove the disincentive of investments in the right things,” Chang said. “How do I remove the barriers of adoption and remove the disincentive of making that technology available?”  

But the success of advancing GETs and HPCs will depend heavily on whether regulators can balance costs. Adequate cost containment for transmission and other investments has yet to be achieved, Chang said, and doing so will require more collaboration between the states and FERC.  

“We need to make sure we contain the costs while expanding our grid to accommodate all the needs we have,” Chang said. “This is where FERC and states and transmission owners should come together and find solutions so that we can transparently explain to the consumers what costs we’re spending. Because ultimately, this is the consumer’s pocket we’re talking about.”