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November 22, 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 5-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 the North American Electric Reliability Corporation (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!

BTW, 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. OMG. As I explained nine years ago, microgrids ignore the incredible efficiency of grid integration. The latest, greatest microgrid is an incredible waste of ComEd 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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Company Briefs

Volkswagen to Invest $5.8B in Rivian in Joint Venture

Volkswagen and Rivian announced they would form a joint venture to develop software and electronics for EVs. Volkswagen said it would increase its investment with Rivian to $5.8 billion from $5 billion, which will include a 50% stake in the joint venture. The partnership will focus on developing software for EVs but could be expanded to include battery modules and other technology. 

More: The New York Times 

Solar Manufacturer Suniva Resumes Production

Officials for Suniva said the solar company has started producing cells at its Georgia factory. The company filed for bankruptcy in 2017 but announced in 2023 it would restart its idled Norcross, Ga., factory thanks to incentives in the Inflation Reduction Act. 

Suniva began producing test cells over the summer and started commercial production a few weeks ago, the company said. Heliene, a Canadian panel maker with a plant in Minnesota, has started receiving Suniva cells as part of a $400 million deal announced in March, both companies said. 

More: Reuters 

Electrovaya Chooses New York for Battery Factory

Electrovaya announced it has chosen Chautauqua County in New York as the location for its gigafactory to make its proprietary Infinity lithium-ion ceramic cells. The facility is expected to lead to more than 250 jobs and support Electrovaya’s exports to Japan, Canada and Australia. 

More: The Post-Journal 

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Federal Briefs

EPA to Charge First-ever ‘Methane Fee’ for Oil, Gas Companies

EPA has finalized a rule that will charge oil and gas companies a fee for emitting methane above certain levels. 

The rule follows through on a directive from Congress included in a 2022 climate law. The new fee is intended to encourage the industry to adopt best practices that reduce methane emissions and thereby avoid paying. As outlined by the EPA, excess methane produced in 2024 could result in a fee of $900/ton, with fees rising to $1,200/ton in 2025 and $1,500/ton by 2026. 

However, President-elect Donald Trump is likely to target the fee amid a flurry of expected actions he has promised to deregulate the oil and gas industry. 

More: The Associated Press 

Global CO2 Emissions on Track to Reach Record Highs

Global carbon dioxide emissions from fossil fuels are on track to reach a record 37.4 billion metric tons in 2024, a 0.8% increase over 2023 levels, according to data from the Global Carbon Project. 

The increase was not uniform across the world. Emissions most likely will decline in the U.S. and Europe, while fossil fuel use in China has slowed. That was offset by a surge in carbon dioxide from India and the rest of the world. 

A small number of countries account for most of the world’s emissions, with China responsible for 32%, the U.S. 13%, India 8% and the EU 6%. 

More: The New York Times 

BLM Seeks Comment on Nevada Solar Project

The Bureau of Land Management announced it is seeking public feedback on a 4,400-acre solar project proposed on public land in Nevada. The Purple Sage Energy Center is expected to generate and store up to 400 MW. The public comment period will end Feb. 13. 

More: KSNV 

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State Briefs

ALABAMA 

Alabama Power Files for Purchase of Autauga County Natural Gas Plant

Alabama Power representatives filed a petition with the Public Service Commission on Oct. 30 to acquire the Lindsey Hill natural gas power plant. Alabama Power said it will need an additional 1,200 MW by the end of the decade. The Lindsey Hill station can generate up to 900 MW. The utility expects to recoup the cost by increasing residential rates by $3.80/month. 

More: Alabama Reflector 

COLORADO 

PUC Approves Xcel Energy Gas Hike

The Public Utilities Commission recently approved a $130.76 million increase for Xcel Energy natural gas customers. The average monthly residential bill will rise by $4.57, while the average bill for small businesses will rise by $17.49. The new rates went into effect Nov. 5. 

More: The Denver Post 

Sen. Hansen to Leave Legislature for La Plata Electric Association

The La Plata Electric Association has announced state Sen. Chris Hansen will take over as its next CEO. Hansen plans to resign from the legislature Jan. 9, the day after the state’s 2025 lawmaking term begins. He recently was reelected to a second four-year term. In addition to serving as a state senator, Hansen is the founder and executive director of the Institute for Western Energy and has more than 25 years of industry experience. 

More: The Colorado Sun 

FLORIDA 

Supreme Court Backs Approval of Storm Plans

The Florida Supreme Court has rejected a challenge to the Public Service Commission’s approval of long-term utility plans for Florida Power & Light, Duke Energy, Tampa Electric and Florida Public Utilities. Justices unanimously upheld decisions that the PSC made in 2022 to approve “storm-protection plans” for the utilities. 

The Office of Public Counsel went to the Supreme Court after the 2022 approvals and argued the commission erred by not considering whether projects included in the plans were “prudent.” But the Supreme Court said the commission “correctly reviewed and approved the utilities’ proposals after concluding that they are in the public interest.” 

More: WUSF 

Tampa Electric Could Seek $400M for Hurricane-related Costs

A quarterly financial report filed at the Securities and Exchange Commission indicates Tampa Electric could seek to recover $45 million to $55 million related to Hurricane Helene and $320 million to $370 million related to Hurricane Milton from customers. 

The utility would need to seek approval from the Public Service Commission and said it will “determine the timing of the request for recovery of Hurricane Helene and Hurricane Milton costs at a future time.” 

More: News Service of Florida 

KENTUCKY 

East Kentucky Power Planning Natural Gas Expansion, Coal Conversion

East Kentucky Power Cooperative has announced plans to build two new natural gas-fired power plants and convert its two existing coal-fired plants to “co-fire” natural gas. 

One 745-MW natural gas plant would cost about $1.3 billion and be located at the John Sherman Cooper Power Station site. It is anticipated to be operational by 2030. The other $500 million, 214-MW plant would be in Casey County. The coal conversions would include one of two units at the John Sherman Cooper Power Station and all four units at the Hugh L. Spurlock Power Station. 

More: Kentucky Lantern 

MISSOURI 

Spire to Lower Monthly Gas Bills in St. Louis Area

Spire, a natural gas provider in the St. Louis area, is set to decrease monthly bills for customers by an average of 16%. The Public Service Commission approved Spire’s plan through which customers will see a $15 bill decrease, starting Nov. 15. The decrease is due to a new purchased gas adjustment approved by the PSC as well as lower gas prices and the recovery of deferred costs from 2021 winter storms. 

More: KTVI 

NEW YORK

NY Waterway Completes Renewable Diesel Trial

New York Waterway said it has completed its renewable diesel trial and is now moving forward with the energy source ahead of hybridizing its fleet next year. The company began its renewable diesel trial this past July on selected ferries and is on track to use 375,000 gallons over the next year – roughly 20% of the fleet’s fuel consumption – with a goal to increase to 50% in the future. 

Renewable diesel fuel, made from various fats, oils and waste products from the food and restaurant industries, performs as well as fossil diesel, but with a significantly reduced environmental impact. The EPA estimates that using renewable diesel can lower greenhouse emissions by up to 78% per gallon. 

More: Hudson County View 

PENNSYLVANIA

PECO to Add 25 MW of Solar to Energy Mix

PECO Energy announced it has agreed to add 25 MW of solar to its energy mix for customers in southeast Pennsylvania. The utility’s original proposal planned to double the amount of solar energy credits bought through long-term contracts, but that didn’t change the percentage of solar energy within its mix, which remained at 0.5%, the minimum required by the state’s Alternative Energy Portfolio Standards. The 25 MW will be about 1% of the utility’s total energy mix. 

More: WHYY 

TEXAS 

King Proposes Refunds for Unused CenterPoint Generators

Sen. Phil King (R) has filed legislation that would create a process to refund Houstonians for charges associated with CenterPoint Energy’s $800 million lease of generators that went largely unused after Hurricane Beryl. 

King’s bill would underscore “the legislative intent of the original bill” by requiring generators leased by utilities to be fully mobile and available for rapid deployment in the aftermath of a storm or other emergency. The legislation also would require the Public Utility Commission to review generators already leased by utilities. Any lease that did not conform to the terms of the bill would be disallowed and its costs unable to be passed on to consumers. 

A Houston Chronicle investigation found that CenterPoint has never used the 15 32-MW generators leased in 2021. 

More: Houston Chronicle 

VIRGINIA 

Balico Downscales Plans for Pittsylvania Plant, Data Center Campus

Balico, the company behind a natural gas power plant and data center campus in Pittsylvania County, intends to file a rezoning application for a scaled-down version of the project. 

The company’s original plans called for the campus to sit on 2,233 acres. The new plans will shrink to 600 acres but with hopes it eventually will be able to grow beyond that. 

More: Virginia Business 

DEQ Levies Another Fine on Mountain Valley Pipeline

The Department of Environmental Quality has ordered the Mountain Valley Pipeline to pay $17,500 for violating environmental regulations from June to September. Violations include allowing sediment to enter streams and improperly installing erosion control matting. It was the company’s fifth consecutive fine of its kind. 

More: Cardinal News 

Pittsylvania Megasite Wins $1.3B Battery Separator Project

Microporous has announced it will invest $1.3 billion to build a battery separator manufacturing facility at the Southern Virginia Megasite in Pittsylvania County. Microporous has produced separators for lead-acid batteries, the oldest rechargeable battery technology, which is typically used in vehicles and to power grid systems. At the megasite, Microporous will expand into creating battery separators for lithium-ion batteries. The facility will be fully operational by 2026. 

More: Virginia Business 

WEST VIRGINIA

PSC Approves Modifications to Solar Farm

The Public Service Commission has approved modifications to a 300-MW Nedpower Mount Storm wind farm project to reduce 132 turbines to 78. The modifications would increase efficiency, reduce impacts on the view, cut down on the shadow flicker from the blades and reduce the noise level. They also extend the life of the facility by 35 years. The company proposed to begin work by July 2025. 

More: WTRF 

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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.