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December 3, 2024

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Markets+ ‘Alert’ Covers CAISO’s Dual Roles as Market Operator, BA

CAISO will be inherently compromised in its role as an operator of a deeper Western market because of its conflicting responsibilities as balancing authority within that market, a group of entities that support SPP’s Markets+ over the ISO’s Extended Day-Ahead Market (EDAM) argue in their latest “issue alert.” 

“An organized market that lacks a fully impartial market operator exposes its participants to shifts in hundreds of millions of dollars of economic value, shifts in reliability risk and shifts in environmental benefits because of the actions that the market operator takes or does not take,” the “joint authors” wrote in the Nov. 14 alert, the sixth in a series of seven such pieces touting the benefits of Markets+. 

The contributors include Arizona Public Service, Chelan County PUD, Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association and Tucson Electric Power — all of whom helped fund the Phase 1 development stage of Markets+. 

The latest alert is possibly the most technically complex because it focuses on the multi-layered processes CAISO uses to manage operations in its real-time Western Energy Imbalance Market (WEIM), which has grown to cover more than 80% of load in the Western Interconnection since being launched in 2014. 

“Over the past decade, in its [emphasis theirs] commingled roles as a balancing authority, transmission service provider and market operator, the California ISO has taken a range of actions and operational decisions for the benefit of the California ISO’s Balancing Authority Area and/or transmission service territory that significantly impact market outcomes for all participants,” the authors write. 

In an email to RTO Insider, CAISO spokesperson Anne Gonzales said the ISO is “proud of the integrity and transparency with which we have managed our multiple responsibilities and the many trusting partnerships we have built with balancing authorities, policymakers and other stakeholders across the West” in operating the WEIM. 

CAISO’s dual roles in the WEIM have become a recurring point of debate in the competition between Markets+ and the EDAM, particularly in discussions around the Bonneville Power Administration’s day-ahead market participation decision process. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.)  

In the Nov. 14 alert, the joint authors zero in on four complaints from the Markets+ camp regarding CAISO’s operational practices in the WEIM. 

Load Conformance

The first of those complaints deals with the WEIM market process known as “load bias” or “load conformance,” which allows a BA to adjust its demand forecast in the hour-ahead scheduling process (HASP) and 15-minute market (FMM) to better position itself for a real-time interval. 

The alert contends that as a BA in the WEIM, CAISO has a history of making unusually large upward adjustments to its demand forecasts during morning and evening peak hours “to acquire flexible capacity through additional energy imports rather than explicitly purchasing flexible capacity itself.” 

The authors say that while load conformance is available to all WEIM participants, CAISO’s “very large and systemic upward-load biasing” for its territory “appears to be unique.” 

As an example, the alert points to a period during a July 2023 heat wave in which CAISO’s average load bias in the FMM during the evening peak was about 1,800 MW but reached as high as 5,000 MW.   

“This is a continuation of an ongoing pattern of load biasing for the California ISO service area that first began in 2017,” the alert argues. It adds that “consistently intervening in the WEIM through manual operator adjustments that do not reflect actual system conditions” is likely to increase production costs and market prices in ways that don’t reflect marginal costs, while signaling that market design elements such as the WEIM’s Resource Sufficiency Evaluation (RSE) and flexible ramping product are inadequate to ensure reliability. 

The authors also point to a previous statement by CAISO staff that load conformance is “significantly used” by the HASP and FMM “to position resources and secure additional intertie capacity.” But in a 2022 analysis that examined the issue, CAISO said it found “no evidence that load conformance causes a one-to-one increase” in WEIM transfers into the ISO.  

It also found that use of load conformance does not improve CAISO’s ability to pass the WEIM bid range capacity and flexible ramping tests, but instead reduces the ISO’s ramp capability, making it more difficult to pass the flexible ramping test.  

“The concern that load conformance could create more headroom on CAISO resources by unloading internal resources with increasing transfers was not validated,” the ISO said. 

In an interview with RTO Insider, CAISO Director of Market Analysis and Forecasting Guillermo Bautista Alderete said the load conformance actions cited in the alert actually comes with a cost for the ISO. 

Alderete said when CAISO applies load conformance in the HASP, FMM or real time, it effectively increases the ISO’s demand requirement. 

“That has an effect that is going to dispatch supply up, and the consequence is that the prices are going to reflect that,” he said. “So when we clear the real-time market, the clearing prices are already reflecting the need — that we have asked for additional requirements to clear. It doesn’t come for free, because now the CAISO area — CAISO load — has to pay higher prices because of the consequence of having this load conformance,” which also translates into higher prices paid to exporters into the ISO. 

WEIM Transfers

The alert’s second complaint refers to CAISO’s blocking of WEIM transfers “to support California’s reliability.” The alert points specifically to a period over July-November 2023 when the CAISO BAA blocked import transfers from the WEIM in the HASP and FMM — but not in real-time — during net peak load hours.  

As the authors note, CAISO’s Department of Market Monitoring (DMM) later said “the transfer limitation had the intended effect of increasing hourly block imports into the CAISO area and decreasing hourly block exports out of the CAISO area to protect reliability during peak net load hours in late July through mid-August.” 

The DMM also determined the practice “created a significant, systematic modeling difference between the 15-minute and five-minute markets, which impacted market results in several ways,” including increasing congestion into the CAISO area from other WEIM areas in the FMM compared with the real-time market, lowering the WEIM’s FMM prices relative to real time in the Desert Southwest and reducing the amount of energy that could be scheduled out of the Southwest in the HASP and FMM. 

“While causing adverse consequences across the market footprint, these California ISO operator actions may not have been effective at enhancing reliability in the California ISO’s service area, as DMM found that ‘[u]nder most conditions, it seems that limiting transfers would not provide significant reliability benefits, but would have negative market impacts,” the alert notes. 

The joint authors expressed concern that the import limits continued even after initial reliability concerns of late July and early August had passed and by “a lack of transparency” that they were even occurring, saying the first mention by CAISO was in mid-September almost two months after they began. 

In a May 2024 presentation to the CAISO Board of Governors and Western Energy Markets Governing Body, the ISO explained that the ISO started the limits after large volumes of WEIM transfers scheduled in the HASP began failing to materialize in real time. 

Alderete said a “key piece of information that is typically neglected” is that CAISO was attempting to reduce its reliance on WEIM imports in response to the market behavior. 

“We were limiting ourselves to not rely too much on the EIM transfers because from the operational point of view, we wanted to be as clear as possible [about] how much internal supply we could have available to meet our own needs. We were insulating ourselves — basically isolating ourselves — from the rest of the EIM market,” he said.   

Alderete said the ISO ceased the practice in November 2023 after it fixed three market issues, including inaccurate display of dispatchable capability in the WEIM, scheduling and tagging processes that allowed participants to ignore export reduction and inconsistent treatment of intertie transactions among BA that increased congestion.  

“Limiting the transfers is one of the tools that any balancing area participating in the market has, including … CAISO. We are not the first one to use it; we are not the only one using it,” he said. 

‘Limited Transparency’

The alert reprises another common contention by Markets+ supporters: that CAISO can’t be trusted to fairly manage the WEIM’s Resource Sufficiency Evaluation (RSE), which is the market test run ahead of every delivery interval to ensure all participants are making enough capacity available to avoid leaning on the market to meet their energy needs. 

They contend that WEIM participants have “limited transparency” into CAISO’s specific inputs and calculations when applying the RSE, which was “routinely failing to identify instances in which” CAISO’s own area didn’t have sufficient resources. 

“Even in hours that the California ISO declared an energy emergency, such as during the August 2020 and September 2022 heat events, the RSE still frequently allowed the California ISO area to ‘pass’ the RSE,” the authors say. 

This points to a larger problem with the RSE, according to the authors: that a resource-deficient WEIM participant is allowed to continue importing the amount of energy it was importing during a previous interval in which is passed the test, without facing an additional financial penalty. They say the rule is “uniquely beneficial” for CAISO because, unlike other WEIM entities, “it typically begins importing large quantities from the rest of the WEIM in the hours leading up to the afternoon peak, driven in part by the large quantity of upward load bias applied by CAISO operators.” 

“This is very different from other WEIM entities that are often importing very little (or even exporting) immediately prior to an RSE failure. Those entities face much more significant limitations on their ability to access WEIM imports without financial penalty,” the alert says. 

Alderete countered that RSE rules apply in a uniform way to every BA across the WEIM, including CAISO, and that the ISO has been “very transparent about the design features of that model” and has in recent years undertaken a series of stakeholder policy initiatives to refine the mechanism. 

He also said it was “misleading” to contend CAISO faces no financial penalties for failing the RSE, adding that the ISO soon will publish an analysis showing how it did incur such penalties during the past summer.  

Congestion Rent Debate Continues

The alert concludes with criticism of CAISO’s treatment of congestion revenue rights (CRR) in its market, a subject that became a kind of proxy for the debate between Markets+ and EDAM supporters after a January 2024 cold snap triggered energy emergency alerts in BAs throughout the Northwest because of supply shortages. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.)  

During that event, the authors note, CAISO collected high transmission congestion rents on power flowing across the Pacific AC Intertie (PACI), which is jointly operated by CAISO and entities in the Northwest, but distributed congestion revenues it collected only to its own participants and CRR holders. 

“[T]he coordinated physical capability of the multi-state transfer path is modeled by the California ISO using a ‘scheduling constraint’ that is applied as a limitation on the quantity of energy that can be imported into or exported out of California,” the alert states. “California ISO’s choice to model the coordinated limit of the overall multi-state transfer path as a limitation ‘inside’ the California ISO ensures the congestion revenue associated with the overall multi-state path is collected and allocated back to [sic] exclusively to customers of the California ISO.” 

The authors say a “similar dynamic” of rent allocation has played out during summer heat waves when CAISO has imported power from the Northwest. 

CAISO contested the Markets+ supporters’ assessment practices during a CRR “myth-busting” presentation to the WEIM’s Regional Issues Forum in September. (See CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap.)  

And in his interview with RTO Insider, Alderete repeated an argument CAISO has raised previously: that the ISO is the only day-ahead market that provides a market solution to manage congestion, which occurs only south of the “constraint.” 

“There is no price signal for doing congestion management in the other northern part of the constraint. That is the problem when you don’t have a market on the other side. There is no mechanism to be able to dispatch, to move resources, to [do] price congestion. All that is basically manually done,” he said. 

The joint authors’ seventh and final issue alert will cover “durable customer benefits.” 

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NYISO Board Approves RNA, 2025 Budget

The NYISO Board of Directors announced at the Liaison Subcommittee meeting Nov. 19 that it approved the ISO’s 2025 budget and incentive goals. (See NYISO Updates Stakeholders on Budget, 2025 Goals.)

The board also approved two items that have been the subject of intense discussion between stakeholders and NYISO this year: the 2025-2029 Demand Curve Reset and the 2024 Reliability Needs Assessment. (See NYISO Management Committee Passes 2024 Reliability Needs Assessment.)

The board was asked whether it discussed the issue of the RNA’s finding that expected large, “flexible” loads, primarily cryptocurrency mining facilities, would eliminate an initially projected statewide capacity shortfall. Several stakeholders had expressed skepticism about that as the RNA made its way through the committees.

Chair Joseph Oates said the board had “engaged” on that topic, but he did not divulge further details. Oates also said some changes to the DCR that came out of stakeholder oral arguments had been reviewed and considered.

“We can’t share what we changed; you’ll see when we actually make the filing,” he said. Those will come later this month.

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Counterflow: Grid Apocalypse Not

I was minding my own business the other day when The Wall Street Journal ran a special section with the lead article “Five Ways to Disaster-Proof the Energy Grid.”

The article starts out claiming that recent extreme weather has pushed the “aging, overtaxed” grid to its limits, with outages “wreaking havoc on homeowners and businesses.” The alleged culprit is climate change, which is said to get worse.

Flawed Evidence

Steve Huntoon

The only empirical evidence given for these claims is data from the Climate Central organization purporting to show that widespread power outages have doubled from the early 2000s to the period 2014-2023. The problem with this data is that — per Climate Central itself in an earlier report — stricter Energy Information Administration (EIA) reporting requirements were widely implemented after 2003, so the years 2000-2003 must be disregarded in order to have apples to apples. If one looks at Climate Central’s data for the 10-year period 2004-2013 and compares it with the 10-year period 2014-2023, the average number of outages goes from 78 per year to 91 per year. Not much difference.

An authoritative data source not mentioned by the Journal is the EIA, which has reported average annual hours of outage (aka interruption) per electricity customer from 2013 to 2022. That chart is reprinted here. The bottom part of each column shows the average outage hours without major events (principally weather); these basically are unchanged over 10 years, which suggests the grid is not “aging” and “overtaxed.” My past articles disproving Chicken Little claims about the grid are here and here.

The top part of each column adds the average hours with major events (principally weather). The trend seems up, but not dramatically so.

And let’s put the average 5.5 hours of customer outage in 2022 in perspective. That’s 99.94% reliability (5.5 divided by 8,760). Not “wreaking havoc” on customers — contrary to the Journal’s claim.

Wrong Target

Credibility doesn’t improve with the Journal’s suggested ways to “disaster-proof the grid.” For starters, anyone who wants to know anything about “disaster-proofing the grid” should consult experts at NERC, the Institute of Electrical and Electronics Engineers (IEEE) and the national laboratories.

The experts would explain that more than 90% of customer outages originate on local distribution systems, not the transmission/generation bulk power system (BPS). This is important because all of the Journal’s suggested ways to “disaster-proof the grid” are exclusively or predominantly tied to the BPS. Thus, even if they were sensible (which they’re not, per below), they would have a negligible effect on customer outages.

Now, let’s look at each one individually.

Artificial Intelligence

The Journal’s first suggested way to “disaster-proof the grid” is (of course) AI, which is said to enable better predictions to help better plan for extreme weather. My favorite example is replacing copper wiring with fiber-optic cable at substations vulnerable to flooding. The story says fiber-optic cable is “more resilient to saltwater and can be replaced more quickly if need be.”

Minor problem: Fiber-optic cable does not conduct electricity. Oops!

By the way, if anything will “overtax” the grid, it will be AI. How ironic.

Batteries

Moving on, the Journal’s second way to “disaster-proof the grid” is “bolstering batteries.” Right. I’ve explained why batteries are an incredibly profligate way to provide carbon-free reliability. In May I estimated the annual costs of covering renewable droughts in a carbon-free California relative to other no/low carbon options:

    • Long-duration battery storage: $23.9 billion
    • Gas plants with carbon credits: $1.1 billion
    • Gas plants with CCS credits: $1.6 billion
    • Gas plants with CCS retrofit: $4.4 billion

See the difference?

Microgrids

The Journal’s third suggested way is microgrids. As I explained nine years ago, microgrids ignore the incredible efficiency of grid integration. The latest, greatest microgrid is an incredible waste of Commonwealth Edison customers’ money.

Microgrids at U.S. military bases actually reduce national security by substituting microgrids for building-specific backup generation that — unlike a base microgrid — is not vulnerable to distribution-level outages (which make up 87% of all base outages) and cybersecurity threats.

Advanced Conductors

The fourth way given is “better, stronger transmission lines.” Yes, we’ve known for years that reconductoring with advanced conductors can increase transmission capacity on existing lines, and I’ve been a fan. But the various options come with their own varying characteristics (such as “rated breaking strength”), as this report shows. Could they somehow “disaster-proof” the grid or even the BPS? No way.

Demand Response

The fifth way given is “controlling demand,” aka demand response. Demand response is best understood as a counterpart to generation resources — reducing demand on command is the flip side of increasing generation on command. Yes, of course, economic demand response should be implemented, just like all economic resources that can be called upon when needed. But DR can no more “disaster-proof the grid” than other dispatchable resources.

The irony is that those ostensibly concerned with grid reliability want to eliminate dispatchable generation resources (gas, oil, coal), thereby enabling, rather than avoiding, future disasters.

OK, I’ll stop ranting.

Columnist Steve Huntoon, a former president of the Energy Bar Association, has practiced energy law for more than 30 years.

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OMS Survey: Another 1-GW Jump in DERs in MISO Footprint

By the Organization of MISO States’ count, MISO is up to nearly 13.6 GW of distributed energy resources in the footprint.  

Results from OMS’s seventh annual DER survey, released Nov. 18, showed an approximate 1-GW growth from the total 12.5 GW of DERs OMS tallied in MISO in 2023. (See Annual OMS DER Survey Records 1-GW Rise in MISO Residential Capacity.) OMS has been recording 1-GW gains in MISO DERs since 2022. Unlike last year, virtually all the DER gains in 2024 came from non-residential sources.  

Of the counted DERs, OMS said almost 3.1 GW comes from residential sources, representing a less pronounced, 140-MW climb year-over-year. OMS continues to find that solar and demand response are the most popular forms of DERs across all MISO planning resource zones, constituting 42 and 43% of survey totals, respectively. The organization said, once again, non-residential DERs that are registered with MISO account for the most capacity.  

Similar to results from 2023, OMS found the bulk of DERs in Minnesota, Wisconsin, the Dakotas’ Zone 1 and Michigan’s Zone 7. Zone 1 contains about 3.45 GW, while Zone 7 plays host to about 2.75 GW. Those zones individually boast more DER capacity than OMS found systemwide in its first DER survey in 2018 at 2.58 GW.  

Mississippi’s Zone 10 once again has the least amount of DERs, OMS found, at just 67 MW.  

OMS said several utilities responding to this year’s survey “noted a need for state regulatory direction and the benefits of a common data-sharing platform” for DERs. OMS itself has stressed the need for MISO to take the lead on creating an information sharing platform for DERs as part of the RTO’s compliance with Order 2222. During its board meetings, some OMS members have said MISO’s lack of a standardized system for coordinated DER data sharing is a glaring omission as MISO prepares to accept DER aggregations into its markets.  

OMS said most utility respondents reported they’re either implementing or considering implementing advanced metering, demand-side management, a DER management system or another form of improved communication to better use DERs. Most also said their state’s DER interconnection standards need to be updated. Still, the majority said they’re not seeing transmission impacts because of DER growth.  

At a Nov. 11 OMS board meeting, Executive Director Tricia DeBleeckere said this year’s DER survey probably showed more DERs because: more utilities responded to the survey; DERs have grown in number; and utilities likely have better tracking and awareness of the resources on their distribution systems.  

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Exelon Leader Discusses Physical Security Programs

With more hostile actors targeting the U.S. power grid, a representative from Exelon said in a webinar Nov. 18 that taking a “proactive” stance on security is more important than ever for electric utilities.

Speaking at ReliabilityFirst’s regular “Technical Talk with RF” webinar, Mike Melvin, Exelon’s director of corporate physical security, reminded attendees that the ongoing reliance of the U.S. economy on electricity has made power facilities increasingly attractive targets for dangerous people both abroad and at home.

“One important bullet [point] I have been emphasizing over and over with our personnel is, in [a] recent … congressional hearing … it was noted for the first time in modern history that U.S. infrastructure is considered a battle space if we’re ever engaged with a [major] adversary,” Melvin said. “It’s definitely a focus area for people who are not fans of the United States: that if they were … really looking to hurt our country, critical infrastructure is an absolute target.”

Exelon has direct experience with such threats, Melvin noted, with the company’s subsidiary Baltimore Gas and Electric having been the target of a planned attack by two white supremacists before their arrest last year. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) The FBI accused neo-Nazi leader Brandon Russell and his associate Sarah Beth Clendaniel of plotting to attack electric substations in Baltimore in order to cause a race war in the city and then nationwide. Clendaniel pleaded guilty in September to conspiring to damage electric facilities and carrying an illegal firearm and was sentenced to 18 years in prison. Russell is in custody and set to go to trial next year.

Brandon Russell | Pinellas County Sheriff’s Office

While Melvin credited the “great work by the FBI” for preventing the plotters from carrying out their threat, he said the incident showed how modern technology makes the planning process for such an attack much faster. Even people like Russell and Clendaniel, with no background in electrical engineering or infrastructure planning, can easily access the information they need to develop a potentially effective plot.

“At one point in her life, [Clendaniel] thought it was a good idea to hold up a convenience store with a machete while she was several months pregnant,” Melvin said.

“I would argue that … somebody that would do something like that is not going to be of high intelligence or a sophisticated criminal,” Melvin continued. “And yet, I will tell you, due to open-source mapping that’s readily available, not just in this country but the whole world, they were able to [make] their plans, which was, basically, they wanted to lay the city of Baltimore to waste by cutting out all the power.”

Melvin acknowledged that the electric industry has a history of reacting to incidents, and said one of the biggest challenges for utilities has been working proactively to neutralize threats before they are acted on.

As an example of the progress that Exelon has made in this regard, he cited the company’s personnel security protection program (PSPP). Melvin said these programs have become more common in the industry as utilities have recognized that they “operate in some areas that unfortunately have very high violent crime rates.”

The PSPP includes programs for analyzing crime statistics and identifying “security awareness areas” where personnel are likely to require protection. Melvin said security incidents have significantly decreased since the introduction of the program.

Another threat mitigation program is the facility enhancement program (FEP), which Melvin said is Exelon’s biggest security program so far. The company began the FEP after the armed attack on Pacific Gas & Electric’s Metcalf substation in 2013, in which gunmen fired an estimated 150 rounds that caused the loss of 52,000 gallons of cooling oil. (See Substation Saboteurs ‘No Amateurs’.)

The FEP involves evaluating the utility’s transmission and distribution substations, gas plants, gas regulator stations and other facilities, and assigning each a tiered threat level. Then Exelon makes security upgrades such as fencing and cameras according to the needs of each tier.

Most important, Melvin said, is to make sure the entire organization understands the importance of security and the danger of neglecting details. He recommended ensuring clear communication across all business lines to make sure as few details are overlooked as possible.

“It’s not all about substation security. You can’t have all your eggs in one basket,” Melvin said. “Your security program really needs to be in partnership with your resiliency program, your supply program … your flood mitigation [program], etc. … It’s not a one-size-fits-all approach when it comes to security.”

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Mass. Energy Leaders Talk Barriers to Innovation at NECA Conference

BOSTON — Massachusetts lawmakers and industry members must double down on efforts to rapidly scale up new renewable technologies to meet the needs of the energy transition, speakers at the Northeast Energy and Commerce Association’s Energy Innovation Forum on Nov. 14 emphasized. 

“If there is one aspect of this work that truly worries me, it is not innovation; … it is deployment,” said Ben Downing, vice president of public affairs for The Engine Accelerator, a public benefit corporation spun out of the Massachusetts Institute of Technology in 2016. 

Downing spoke optimistically about the “cavalry of new solutions coming in waves” to help the clean energy transition, including nuclear fusion, deep geothermal energy, long-duration energy storage and superconducting transmission lines. 

But even with solutions on the horizon, “I worry about our ability to deploy with the combination of speed and scale that is required,” Downing said. “Getting those concepts to commercialization is on all of us.” 

In the power sector, utilities and regulators will need to evolve their approach to new technologies, said Sarah Cullinan, senior director of the Net Zero Grid Program at the Massachusetts Clean Energy Center. 

“Our utilities are very open to innovation, but the landscape and the process make it really difficult,” she said. “The scale aspect for utilities is entirely determined within the Department of Public Utilities, and it’s ultimately ratepayers that would fund the full-scale deployment of any new technology.” 

Utilities have “very little room for error” in deploying new technologies, Cullinan said, adding that “the question is how do you test something on that system in a way that gives you the data and information that you need without compromising reliability.” 

Cullinan specifically cited grid-enhancing technologies as a key area of potential technological improvement on the distribution side, especially as they have gained traction in transmission applications. 

“I’m hoping that some of that can be scaled to distribution,” Cullinan said. 

Downing expressed hope that the changes to clean energy siting and permitting recently passed by the Massachusetts legislature would help expedite the deployment of new resources. (See Compromise Climate Bill Finally Approved by Mass. Legislature.) 

However, Jenny Liu of Jupiter Power stressed that interconnection backlogs still pose a major hurdle to development in the region. 

“It’s just taking too long to get through the process, and therefore, we can’t deploy [renewables] to solve the capacity deficiency pretty much everywhere,” Liu said. “This is a big problem; only if we get it solved will there be a big breakthrough in the renewable energy industry.” (See related story, Stakeholders Push for More Interconnection Rule Changes at FERC.) 

While FERC Order 2023 requires major changes to interconnection procedures across the country, the commission has yet to rule on RTO compliance filings, creating significant uncertainty for New England developers. (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty.) 

On the consumer-facing side, the industry must work to educate and prepare customers for the rollout of advanced metering infrastructure (AMI) and time-varying rates, Cullinan said. Eversource Energy, one of the two major electric utility companies in Massachusetts, has said it will start deploying advanced meters in the state in 2025. 

Vinit Nijhawan, managing director of MassVentures, said the state must find a way to move faster to implement time-varying rates. 

“It’s not about the technology,” Nijhawan said. “We’ve been talking about time-of-day rates for as long as I’ve been here, which is 37 years. 

“We’ve got to move faster than we’re moving. … We need imagination.” 

At the same time, Nijhawan praised the state’s overall climate of fostering innovation.  

“Massachusetts is the most amazing place for new ideas to flourish. We don’t need to change much; I think it’s all there,” he said.

Regarding the potential effects of a second Trump administration on the state’s clean energy transition, Cullinan said there is “a lot of uncertainty” about the availability of federal funding going forward. 

“Across the entire state that question is popping up. There really is an effort to figure out what is at risk,” she said. “Luckily, we live in a state where there is a lot of funding and support still.” 

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‘Holistic’ Approach Needed for Tx Planning, NARUC Panelists Say

ANAHEIM, Calif. — To ensure a cost-effective energy transition, stakeholders must approach transmission planning holistically and avoid piecemeal investments, panelists argued during the National Association of Regulatory Utility Commissioners’ Annual Meeting from Nov. 10 to 13.

The total investments needed to meet the expected load growth “could easily exceed what individual market participants can finance or recover,” said Johannes Pfeifenberger, principal at The Brattle Group.

“Effective outcomes really require a multifaceted approach,” Pfeifenberger said. “On the transmission side, that means more comprehensive, holistic, proactive planning. We’re spending a lot on transmission incrementally, but we really need to plan that to achieve cost-effective outcomes with the least regrets.”

Some potential approaches Pfeifenberger highlighted include planning to avoid under- or overbuilding, loading order, cost control incentives and moving away from a compartmentalized transmission planning process.

Maine Public Utilities Commissioner Patrick Scully said the New England region has invested heavily in transmission, with annual transmission system charges rising from $869 million in 2008 to $3.3 billion in 2025.

However, the region failed to implement efficient public policies to go with the transmission, which has resulted in lost opportunities to bring more low-cost generation to fruition, Scully said.

The New England states decided to join forces and collaborate on the future of the grid, Scully said.

As a result of this collaboration, ISO-NE issued a report last year, which found that peak loads in New England would double from 28 GW to 57 GW by 2050. The transmission upgrades needed to meet this load could cumulatively cost between $22 billion and $26 billion, according to the study. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

“And at the request of the states, ISO agreed to establish a tariff process by which the states collectively can request that ISO issue [a Request for Proposals] to solicit competitive transmission project proposals that address the needs that have been identified in that 2050 study,” Scully said. FERC approved the changes in July.

The price tag to meet future transmission needs coming from heavy loads like data centers and chip manufacturing will be “tremendous,” said Karen Onaran, CEO of the Electricity Consumers Resource Council.

Onaran agreed with Pfeifenberger that transmission planning has so far been “very siloed,” which has resulted in limited generation options that could potentially drive down costs.

“We are encouraged by this recognition that we need more transmission,” Onaran said. “We absolutely see the big price tag. Let’s make sure that we are all coming together to figure out the solution.”

California has seen increased opportunities for interregional transmission, according to Neil Millar, vice president of transmission planning and infrastructure development at CAISO. Working across a broader footprint will enable the region to take advantage of the region’s diverse resources more efficiently, Millar added.

“Clearly, the better interregional coordination would be to the betterment of all,” Millar said.

MISO Vice President of System and Resource Planning Aubrey Johnson said there has to be a regulatory framework in place to encourage cost-effective transmission planning.

“Ultimately, if we want to see more transmission planning and more proactive stuff, it actually needs to start in a regulatory framework where people are encouraged, incentivized and challenged up to the table to do those things,” Johnson said.

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Not Waiting for Trump, DOE Sends More IRA, IIJA Funds to Red States

With just two months until President Joe Biden’s administration ends, the U.S. Department of Energy continues to fund projects with federal dollars from the Inflation Reduction Act and Infrastructure Investment and Jobs Act. President-elect Donald Trump may find it hard to claw back the money. 

Like much of the IRA funding, the latest DOE awards are going to states and districts that voted for Trump, and to projects with a lot of local and national media appeal. Pulling the plug on popular projects could create a virtual minefield for the president-elect and his DOE nominee, Chris Wright, CEO of a major fracking firm, Liberty Energy. 

For example, on Nov. 13, DOE’s Office of Clean Energy Demonstrations (OCED) announced it had finalized a grant of $5 million in IRA funds that will go to the Dallas County, Ala., Board of Education for energy efficiency upgrades at nine schools, many of which were built in the 1950s, according to a project fact sheet. Ancient HVAC systems will be upgraded, and modern building controls installed.  

Three schools also will get rooftop solar systems. The project is expected to take four years, and the money saved on the district’s energy bills could be reinvested in facilities and programs for students. 

In Nevada, OCED signed a contract for a $14.6 million award to Nevada Gold Mines LLC to begin the first phase of a project to install 100 MW of solar and close to 250 MWh of energy storage to help decarbonize the company’s operations at a processing plant and a working mine. The total federal award for the project is $95 million. 

The project is one of five DOE selected for funding in March under its Clean Energy Demonstration Program on Current and Former Mine Land (CEML) with up to $475 million from the IIJA. Four of the five projects — in Nevada, Kentucky, Pennsylvania and West Virginia — have finalized contracts with DOE. Trump won all four states. 

The fifth project, using geothermal energy and storage to increase production at a copper mine in Arizona, is in negotiations for its $80 million award, according to the CEML webpage. 

These and other funding announcements made since Trump’s victory in the Nov. 5 election could present an obstacle to the president-elect’s plans for rolling back provisions and funding in the IRA, ostensibly to pay for extending his 2017 tax cuts. 

Trump-proofing the IRA

During his visit to the Amazon rainforest Nov. 17, President Joe Biden defended the IRA and its clean energy programs against the rollbacks Trump likely is planning. 

“It’s true some may seek to deny or delay the clean energy revolution that’s underway in America,” Biden said. “But nobody — nobody can reverse it — nobody. Not when so many people, regardless of party or politics, are enjoying its benefits.” 

Christian Roselund, a senior policy analyst at Clean Energy Associates, also is doubtful of a major IRA repeal — in particular, the clean energy investment and production tax credits ― saying the current situation is “complex and nuanced.” 

“A main reason is that Republicans currently hold a six-seat majority in the U.S. House and are unlikely to get more than a seven-seat majority when the final five races are counted,” Roselund wrote in a LinkedIn post. “Meanwhile, of the 18 Republican members of the U.S. House who sent a letter to Speaker [Mike] Johnson [R-La.] opposing ITC/PTC repeal, 13 won reelection, and one race is still undecided.” 

Still another, Rep. John Curtis (R-Utah), won a Senate seat, and “Senate Republicans may be even more hesitant to make sweeping changes that affect projects underway and business certainty,” Roselund said. 

The best way to Trump-proof the IRA funds is to get them out the door as quickly as possible, according to advocates such as Adam Deveny, former director of energy policy for Senate Democratic Leader Chuck Schumer (D-N.Y.). 

In recent months, the pace of DOE award announcements has accelerated, Deveny, founder of Climate Vision, a policy advisory group, told Canary Media. “Getting that money out the door is critical, because any unspent money is at risk of not ever getting spent,” he said. 

The latest money going out the door, on Nov. 18, is close to $15 million for nine research and development projects that will combine hydropower with other renewables and storage “to increase hydropower’s ability to respond to changing demand on the electric grid,” according to the DOE announcement.  

Hydro provides 6% of U.S. power and 27% of the nation’s renewable energy, according to DOE. It also can ramp up or down quickly to ensure flexibility for grid reliability, possibly making it another no-go for potential rollbacks.  

DRG Technical Solutions of Memphis, Tenn., was selected to receive more than $3 million for a project meant to demonstrate the use of hydropower to produce clean hydrogen at a hydro facility in Colorado.  

“That hydrogen can then be stored to provide electricity to the grid when needed, and power or fuel for electric and hydrogen vehicles,” the announcement says. 

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EIA: Distribution, Transmission Led to Higher Utility Capital Spending

Data collected over the past 20 years shows an increase of 12% in utility capital spending, rising from $287 billion in 2003 to $320 billion in 2023. Spending on generation has declined, while spending on transmission and especially distribution has surged and more than made up for declines in cheap generation, according to data from the U.S. Energy Information Administration.

The sector spends 24% less on producing electricity than it did in 2003 due to lower fuel costs and the closure of older power plants that were costly to maintain. But spending on generation jumped 23%, or $4.7 billion, from 2022 to 2023 due to one project coming online — Southern Co.’s Vogtle nuclear plant expansion, which started commercial operation in April.

Spending on transmission nearly tripled over the two decades, hitting $27.7 billion in 2023, with some of the increase coming from transmission station equipment ($1 billion), poles ($1.1 billion) and computer software ($400 million) needed for operating regional transmission markets.

The distribution system was the main driver for overall increases in the utility sector as capital investments in that level of infrastructure were up by $31.4 billion, or 160%.

More than 20% of the increase in distribution spending happened between 2022 and 2023, when utilities spent $6.5 billion more for a total of $50.9 billion to replace and upgrade aging equipment and install new distribution infrastructure to help neighborhood grids withstand extreme weather and manage renewable intermittency.

The biggest categories for distribution system spending were on overhead lines, poles and towers as utilities spent $17.4 billion on overheard infrastructure in 2023. That marks an 11% increase from a year earlier, and 220% more than in 2003.

Spending on underground lines also ramped up significantly over the past 20 years to reach $11.8 billion in 2023. It was for new developments, as well as undergrounding old lines to mitigate power outages from storms and wildfires or improve neighborhood appearance.

Supply chain and manufacturing issues led to utilities spending 23% more for a total of $7.5 billion in 2023 on “line transformers,” which drop voltage to household levels.

Utilities spent $6.1 billion on distribution substations in 2023, which marks a 184% increase from 2003 and 15% from 2022. More substations allow utilities to better withstand extreme weather, manage renewable intermittency and allow for greater voltage control during emergencies.

Another major increase was spending on infrastructure located on or near customers’ property, which includes meters, leased property and rooftop solar. Utilities spent $5.1 billion on that in 2023, up 84% from 2003 and up 25% from 2022.

Although energy storage remains a relatively small portion of the total budget for distribution infrastructure, spending increased from $97 million in 2022 to $723 million in 2023. Energy storage at the substation or customer site enhances power quality and provides backup power in areas where lines and transformers cannot handle additional capacity, especially as more intermittent renewable resources come online.

The “other” spending category increased by 30% or $8.6 billion over the 20 years. It includes intangible plant expenses like licenses and general plant expenses like office space and storage buildings.

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Stakeholders Push for More Interconnection Rule Changes at FERC

Stakeholders are split on whether FERC should adopt more changes to its generator interconnection rules or focus on implementing Order 2023 while letting specific regions go further on their own (AD24-9). 

After issuing the order in July 2023 and working on grid operators’ compliance filings for nearly a year, FERC held a technical conference in September looking into how to further speed up processing the country’s interconnection queues, which according to Lawrence Berkeley National Laboratory include about 11,600 projects totaling 2,600 GW. (See FERC Workshop Examines How to Speed up Interconnection Queues.)  

In post-conference comments, submitted last week ahead of a Nov. 14 deadline, a group of “public interest organizations” — including the Natural Resources Defense Council, Sierra Club, Southern Environmental Law Center and Sustainable FERC Project — urged FERC to ensure that Order 2023 is fully implemented and to focus on future reforms that complement it. 

“Transmission providers’ obstinate, superficial compliance filings and continued litigation against Order No. 2023 underscore the need for the commission to only entertain proposals that would build on — rather than detract from — the reforms of Order No. 2023,” they said. 

They argued FERC should make improvements to surplus interconnection service and energy resource interconnection service (ERIS), which allow new resources to connect to the grid with fewer guarantees for delivery when the system is constrained. The services are not evenly implemented in organized markets, they said, and in some cases, ERIS interconnection costs can exceed network resource interconnection service (NRIS), which is intended to guarantee firmer connectivity. 

“The commission should reject proposals that run counter to open access by allowing new interconnection requests to queue jump: passing on additional uncertainty, delays and unfavorable cost allocations to interconnection customers that have already struggled to maintain viability in extensive queue backlogs and now rely on the Order No. 2023 cluster process,” the groups said. 

Advanced Energy United, the American Clean Power Association and the Solar Energy Industries Association did not warn FERC away from queue jumping entirely, but they cautioned against making that change permanent. Such Band-Aid approaches should be sunset by the end of the decade, they argued. 

“Queue caps and prioritization processes may make models solvable but are likely to prove challenging to design and implement without undermining open-access principles,” the clean energy trade groups said. “Further, inequitable and inconsistent stopgap measures may limit development and ultimately harm reliability. The commission must not lose track of the fact that open access is good for consumers; it reduces costs and drives innovation. This is equally, if not more, true in times of rapid change — like today — as in times of relative stability.” 

The high number of projects is logical and necessary to ensure healthy competition to serve new load, but high queue volumes were cited by other parties as the main problem that needed to be solved with caps and prioritization, the groups said. High project volumes are an issue only if they are a result of a faulty process. 

“A Band-Aid can be a stopgap solution — but if surgery is what’s needed, it should be prepped for, scheduled and performed as soon as possible, even if the Band-Aid is helping to temporarily address symptoms in the meantime,” they said. 

Region-specific Proposals

The Edison Electric Institute said FERC should focus on implementing Order 2023 but also let regions that propose revisions to their own processes to move forward with those. 

“Given the reliability concerns in some regions, EEI believes that the commission should be open to regions proposing reasonable mechanisms to prioritize the interconnection of certain resources to ensure continued reliable energy supplies,” the investor-owned utility trade group said. “Finally, EEI recommends targeted reforms rather than generic action to further integrate the transmission and interconnection processes.” 

New generic, nationally applicable processes risk disrupting ongoing compliance processes, consume significant time and financial resources, and could delay the goals advanced by Order 2023, EEI said. 

American Electric Power called on FERC to ensure ISOs and RTOs have effective, nondiscriminatory processes in place to prioritize or fast track interconnection requests for replacing retiring generation and new capacity needed to meet reliability or resource adequacy requirements. Shovel-ready projects that support reliability, need only existing transmission to connect and support state policies should be prioritized. 

Constellation Energy said FERC should adopt a new method that speeds up the queue, noting that PJM has talked about 2030 as being the year when reliability will come to a head. 

“Accelerating the pace of new entry of reliable resources is critical to solving this problem,” Constellation said. “To do so, Constellation and PJM have proposed stopgap frameworks that would prioritize shovel-ready interconnection requests that address demonstrated resource adequacy or reliability needs.” 

This “Expedited Reliability Process” would have the RTO establish objective criteria to determine whether a project is likely to satisfy the region’s reliability needs and whether it can be constructed on time to meet them. The proposal should be filed with FERC in December, the firm said. 

MISO told FERC it is facing similar issues with narrowing reserve margins and a slow queue, which it has been working to improve through automation and tracking. Part of the problem in MISO is that 58 GW of generation have signed a generator interconnection agreement and have yet to come online. 

“MISO will be launching an interactive tool on our website to understand the fuel type, location and reasons these generators are delayed in coming online,” it told FERC. “Additionally, MISO is pursuing a new study process known as the Expedited Resource Adequacy Study that will allow MISO to study interconnection requests necessary for resource adequacy in a matter of months.” 

The RTO did a survey of those projects, of which 26 GW have announced they expect delays or just not been energized on time. An additional 15 GW responded, with 40% saying the delay was from transmission issues, 18% from regulatory/permitting issues and 11% from difficulties securing power purchase agreements. Equipment supply chain delays dating back to the COVID-19 pandemic are also often a factor. 

Order 2023 is an improvement, but its reforms were narrow, and FERC should continue to work on interconnection issues, argued the Electricity Customer Alliance, the Electricity Consumers Resource Council and R Street Institute. FERC could do another rulemaking or let regional changes bloom, they suggested. 

But they also argued the commission should announce an ongoing forum on the best generator interconnection processes that is held at least annually and articulate its policy objectives by issuing a statement. 

“The salience of GI reform, beyond Order 2023, continues to grow,” the consumer groups said. “Unnecessarily slow and costly GI process has been a growing economic burden on consumers for years. Grid upgrade costs for generators to interconnect have grown by multiples in many regions, and most of these costs are passed through to consumers. Interconnection wait times have increased from less than two years to a median of five years last year, with some regions now explicitly delaying or pausing the processing of new GI requests. GI delays now present a material reliability risk to consumers, especially as expectations for load growth have increased.” 

A New Type of Monitor?

The American Council on Renewable Energy suggested that FERC require regions with delayed queues to set up independent interconnection monitors to evaluate study practices, assumptions and outcomes, and then recommend improvements. 

Grid Strategies published a report this month advocating for a similar concept that would require TOs to hire independent construction monitors “to ensure compliance with timelines, budgets and projects specifications, providing transparent and unbiased evaluation throughout the construction phase.” 

“Available data — and data are very scarce — suggests that transmission owners’ budget priorities and construction management practices may play a substantial role in these construction phase delays,” the report says. “With perhaps half of all projects with interconnection agreements being significantly stalled or facing substantial cost overruns during the construction phase, this is a serious and widespread issue.” 

Construction monitors would get access to often sensitive data and be an independent set of eyes that could identify issues causing delays and make expert recommendations on how to speed up construction and equipment procurement, the report says.