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November 1, 2024

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FERC Black Start Report Pushes Gas-electric Coordination

A study released Dec. 19 by FERC, NERC and the Texas Reliability Entity on black-start resource availability in Texas raises concerns about ERCOT’s dependence on natural gas to kick-start the grid during an emergency (AD24-5).

The study was launched in November 2022, following a recommendation by the commission and NERC’s joint inquiry into the winter storm that caused mass outages across Texas and the South Central U.S. in February 2021. (See FERC, NERC Release Final Texas Storm Report.) Staff focused on the availability of black-start and next-start resources and ERCOT’s procurement of black-start resources for its system restoration plan, while also assessing registered entities’ black-start resource testing, fuel-switching tests, fuel delivery infrastructure and other activities.

A black-start resource is a generating unit and its associated equipment that can be started without external support from the electric grid, or that is designed to remain energized without connection to the broader system. The first generator in a cranking path to be energized using power from the black-start unit is called a next-start unit.

Chanel Chasanov, FERC | FERC

The report indicated that ERCOT has well-defined processes for securing enough black-start resources to meet the needs of its restoration plan. However, ERCOT’s heavy reliance on natural gas for black-start and next-start generation could create problems. Presenting the report at the commission’s open meeting Dec. 19, Chanel Chasanov, of FERC’s Office of the General Counsel, said the study highlighted the “shared responsibility and need for the electric and natural gas industries to work together to plan for a blackout.”

Nine entities participated in the study, according to the report. The team aimed to identify participants that:

    • were subject to NERC reliability standard EOP-005-3 (System restoration from blackstart resources);
    • were located within ERCOT and possess different types of black-start resources;
    • had significant responsibilities during black-start restoration;
    • produced, processed and transported natural gas to black-start and next-start resources;
    • have experienced natural gas curtailments; and
    • have performed black-start resource testing under actual or anticipated conditions.

FERC, NERC and Texas RE staff reviewed documents provided by each participant and conducted on-site and virtual discussions to gain more information. After identifying best practices and opportunities for improvement among the entities, they produced several recommendations for addressing potential shortcomings.

The first set of recommendations applies to entities responsible for developing and implementing black-start restoration plans. Members of the study team advised entities to examine each black-start resource’s limits, including potential fuel issues and single points of failure.

Where possible, utilities should identify a wide range of options to incorporate into their plans, “beyond a reliance on traditional black-start resources,” the study says. Alternate options could include electric bypasses, HVDC ties and nonfuel energy resources, such as inverter-based resources and batteries.

To mitigate the risk of natural gas pipeline failures during outage events, the team suggested that entities add off-site gas storage options to their restoration plans. Report authors also recommended that owners of dual-fuel-capable resources be required to test alternate fuel options to verify they can perform when the primary fuel is unavailable.

Another group of recommendations was aimed at state regulators and other authorities with the ability to “facilitate and moderate engagement among the entities” involved in restoration. These stakeholders were advised to examine the potential impact of a blackout on the gas supply chain, which Texas RE Chief Engineer Mark Henry explained “could help the electric and natural gas industries better understand what action is required in a blackout and which electric and … gas entities are vital for black-start system restoration.”

The team also suggested that state and other authorities consider raising the priority of gas supply and transportation to black-start and next-start resources, as part of a coordinated restoration plan “that incorporates the needs of both the electric and natural gas industries.”

FERC Chair Willie Phillips thanked the team for their work and urged stakeholders to read the report.

“These recommendations are important. It really gets to the heart of what we’ve been talking about all year, which is reliability and resilience, and I cannot underscore how important it is that everyone pay close attention to the work that you’ve done,” Phillips said.

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ISO-NE Details Proposal for Regional Energy Shortfall Threshold

ISO-NE kicked off work to determine an acceptable level of energy shortfall risk for New England at the NEPOOL Reliability Committee’s meeting Dec. 18. 

The project is an offshoot from ISO-NE’s Operational Impact of Extreme Weather Events study, a collaboration with the Electric Power Research Institute to use historical extreme weather scenarios and the expected future resource mix to quantify energy shortfall risks for 2027 and 2032. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) 

The study also led to the development of the Probabilistic Energy Adequacy Tool (PEAT), which the RTO plans to use in future resource adequacy studies. The Regional Energy Shortfall Threshold (REST) would apply to the risk quantified in PEAT studies. 

“Establishment of the REST is intended to define the level of energy shortfall risk beyond which a set of additional, future solutions may be required,” said Stephen George, ISO-NE director of operational performance, training and integration. 

While the first phase of the project is not intended to outline solutions for when shortfall risks are deemed too high, ISO-NE is planning to pivot to solutions once the REST is established. 

“Possible solutions to reducing energy shortfall risk to within REST tolerances could range from market designs, to infrastructure investments, to dynamic retail pricing and responsiveness by end-use consumers,” George said. 

He added that ISO-NE will also use the project to consider the frequency and timescale of PEAT studies, and whether they should be conducted on an annual, seasonal or in-season basis. He noted that the PEAT framework could be used to better understand both long-term and short-term resource adequacy risks. 

ISO-NE is planning to collaborate with the states and stakeholders to establish the risk threshold, George said. The RTO intends to present an initial proposal in May, with some opportunity for stakeholder input prior to the proposal. 

“ISO envisions a multimonth process spanning several RC meetings to allow for proposals, feedback, counterproposals and finalization of the REST toward the end of 2024,” George said. 

Resource Adequacy Assessments

ISO-NE Technical Manager Fei Zeng presented to the RC proposed changes to the Resource Adequacy Assessment (RAA) modeling as part of the ongoing resource capacity accreditation (RCA) project.  

The changes would affect the capacity values of different resource types in the Forward Capacity Market and are intended to more accurately capture resources’ reliability attributes. 

“RAA is used to establish capacity requirements and demand curves and, under RCA, resource accreditation,” Zeng said. “Improvements to the RAA will better identify when loss-of-load events occur and their duration and will improve how individual resource performance is reflected during these events.” 

Zeng said the main motivations for the RAA changes are to more accurately model system conditions; improve the assessment of resource performance and interactions between resources; increase the modeling consistency between resource types; and “better reflect the correlation between resources’ performance and system loading conditions and weather.” 

Capacity Accreditation of Seasonal Tie Benefits

Zeng also presented changes to the evaluation of tie benefits in the RCA project, aimed at better capturing seasonal differences in values. 

Tie benefits quantify the reliability contributions of grid connections between New England and neighboring regions. While current values are based on summer peak load conditions, the RCA project requires a more accurate assessment of winter tie benefit values, Zeng said. 

Zeng said the tie benefits provided by New York are similar during winter and summer because the state has a similar load profile to New England’s. He noted that the benefits “are mainly the result of resource random outages and diversity.” 

Because Quebec and the Maritime Provinces are winter-peaking systems, the regions’ tie benefits to New England are likely lower in the winter than in the summer, when the regions have more surplus capacity available, Zeng said. 

For the RCA process, which is not intended to change the underlying tie benefit calculation methodology, ISO-NE is planning on using an approximation approach to quantifying winter tie benefits. This approach would approximate the winter tie benefits from New York, Quebec and the Maritimes based on the simulated summer tie benefits from New York. 

Based on this approach, the winter tie benefits from Quebec and New York would be equal to the latter’s simulated summer tie benefits, while the Maritimes’ winter tie benefits would be set at half of this value. 

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DOE Issues Final Guidelines for National Transmission Corridors

The Department of Energy has released its final guidelines for the designation of National Interest Electric Transmission Corridors (NIETCs), which are narrowly defined areas where transmission is urgently needed to ensure power reliability and affordability and to advance “important national interests.”

DOE was authorized to designate such corridors in a “nonbinding process” through the Infrastructure Investment and Jobs Act, according to the guidelines issued Dec. 19.

As defined in the guidelines, a NIETC is “a geographic area where … DOE has identified present or expected transmission capacity constraints or congestion that adversely affects consumers. … One or more transmission projects could be located within that geographic area to alleviate such constraints or congestion.”

NIETC designation “unlocks” federal money and permitting tools to accelerate transmission construction, such as programs that allow DOE to sign on as an anchor off-taker for transmission projects, and direct loans made available by the Inflation Reduction Act.

DOE announced its first proposed off-taker agreements in October, with up to $1.7 billion invested in three interstate transmission projects. (See DOE to Sign up as Off-taker for 3 Transmission Projects.)

The IIJA also authorized FERC to issue permits for transmission projects within a NIETC if a state lacks authority to issue a permit, has delayed action on a permit application for more than a year or has denied the application.

The guidelines lay out a four-step process for NIETC designation: information collection on potential NIETCs; the publication of a preliminary list of proposed NIETCs; completion of environmental or other reviews, “robust public engagement” and the release of draft NIETC designation reports; and one or more final NIETC designation reports with related environmental documents.

“Improving and expanding national transmission infrastructure is essential to not only meeting President Biden’s clean energy goals, but also to ensuring that people across the country have access to resilient, affordable power,” Maria Robinson, director of DOE’s Grid Deployment Office, said in a DOE press release.

“Consumers are frequently harmed from a lack of transmission infrastructure, which can directly contribute to higher electricity prices, more frequent power outages from extreme weather and longer outages as the grid struggles to come back online,” according to the press release. “While these needs are urgent, building and expanding transmission often requires several years of permitting, siting and regulatory processes, especially if the line extends through multiple states and regions.”

‘Any Interested Party’

DOE was first authorized to designate transmission corridors in the Federal Power Act of 2005, according to a report from the department’s Electricity Advisory Committee. The law also allowed FERC “backstop” permitting authority — that is, allowing the commission to issue a permit even if a state was opposed to a project. Those provisions were ruled unconstitutional because they did not provide clear enough definitions of what conditions would trigger the backstop authority.

The IIJA amended the 2005 law to provide more clarity on DOE’s ability to designate the renamed NIETCs and FERC’s ability to permit interstate or interregional transmission.

The final guidelines incorporate feedback DOE received in the 112 comments it received following the Notice of Intent and Request for Information on the NIETC designation process, which it issued in May. For example, state officials, RTOs and advocacy groups were concerned that transmission developers might have too much influence in the NIETC designation process. (See States, RTOs Caution DOE on Transmission Corridors.)

The guidelines acknowledge this feedback and open eligibility to provide information and suggest corridors to “any interested party.”

“DOE does not prioritize NIETC designation based on which interested party submits information and recommendations. … As commenters suggest, opening eligibility may spur collaborative transmission development among traditional developers, load-serving entities (including public power entities and Indian tribes), states and local governments, and others.”

Robinson similarly stressed that DOE has pursued “meaningful, collaborative and widespread stakeholder engagement into our NIETC designation process to make sure we can clearly identify the areas that are the nation’s highest priorities for transmission and bring critical infrastructure there first.”

The release of the 66-page guidelines will kick off a comment period that will run through Feb. 2. DOE is targeting spring 2024 for a preliminary list of potential NIETCs.

NIETC vs. Transmission Planning

In evaluating potential NIETCs, the guidelines state that DOE’s National Transmission Needs Study, also released in October, will be a primary, but not the only, source of information for corridor designation.

The triennial report provided a breakdown of regional and interregional transmission needs, pointing to the higher electricity prices and reliability concerns grid congestion and constraints can have on consumers. From 2019 to 2020, the guidelines say, “congestion on interfaces across all [Western non-RTO/ISO] markets (day-ahead, 15-minute and 5-minute) increased by 74% from $152 million in 2019 to $263 million in 2020, primarily due to increased congestion.”

Looking ahead, the guidelines predict the effects of inadequate transmission will intensify. Massive growth in interregional transfer capacity may be needed, such as a 255% increase between New England and New York.

The guidelines’ summary of Needs Study suggests all regions may benefit from NIETCs. But, again noting stakeholder input, the guidelines stress the NIETC process isn’t intended to disrupt or supplant, but to complement existing transmission planning.

“In particular, DOE can use the NIETC designation process to identify valuable areas for transmission development that these existing transmission planning processes may not be identifying,” the guidelines say. “Existing transmission planning processes are largely constrained by their focus on regional or local needs, whereas the NIETC designation process can examine interregional needs.”

DOE also will use a “threshold need determination” to help identify possible NIETCs, based on the current status and future expectations of congestion or lack of capacity that may affect consumers, the guidelines say. Only areas that pass that screening will continue in the designation process.

Advocates and industry analysts are still reviewing the guidelines, but they shared initial reactions with RTO Insider.

Rob Gramlich, president of Grid Strategies, a research and consulting firm, said he’s glad to see DOE moving ahead with the process, but cautioned “it is better for all parties involved for the process to focus on actual routes which the … process allows. If they are not using that, they will need to find another way to focus on meaningful, narrow corridors.”

Elise Caplan, vice president of regulatory affairs at the American Council on Renewable Energy (ACORE), said her organization “supports DOE’s preliminary finding that the greatest value for NIETC designation will be in geographic areas where DOE has found a need for increased interregional transfer capacity.”

“DOE also properly critiques the shortfalls in transmission planning and the absence of planning for larger-scale, regional and interregional transmission ‘that may address multiple transmission needs in a wider area more cost effectively than the piecemeal transmission expansion that dominates today,’” Caplan said. “ACORE supports the use of the NIETC designation process as one of many tools to address this shortcoming.”

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New Jersey EV Charger Bill Sparks Scrutiny of Demand Charges

A bill before a key New Jersey Senate committee that seeks to accelerate the installation of direct current fast chargers (DCFCs) by giving commercial charger operators a break on rates sparked a battery of concerns over who should pick up the tab.  

Developers, electric vehicle advocates and environmentalists expressed concerns about the bill, S3914, in a hearing Dec. 18 of the Senate Environment and Energy Committee. The bill would require electric public utilities to submit new tariffs on commercial charging station operators for approval to the Board of Public Utilities (BPU). It would require the tariffs to be an alternative to “traditional demand-based rate structures.” 

The tariffs also would be designed to “establish cost equity between commercial electric vehicle tariffs and residential tariffs” so the entire burden does not fall on the charging station operator. The bill is designed to create an investment environment that would promote third-party investment in electric vehicle (EV) charging technology. 

Demand charges are triggered by an unusually high peak in power consumption, at which point the customer is billed an extra rate because the provider must invest more to meet the higher-than-normal power demand. That contrasts with energy charges that determine customer payments based on the amount of power used over a sustained period. 

Critics of demand charges in the EV charging environment say charging station operators could end up paying high electricity charges even though the overall use of the charging point is low, a scenario more likely when there are relatively few EVs on the road. That would occur, for example, if three EVs charged at the same station at once, pushing up momentary demand and triggering a relatively high demand charge, even though the site gets little use most of the month. 

The committee heard discussion on the bill, but did not vote, in line with the directive in advance of the meeting by Chairman Sen. Bob Smith (D), the bill’s sole sponsor, who sought only to collect public input. The committee is one of the most prominent voices on clean energy in the legislature, which will conclude its business Jan. 8.  

Smith, who expects to offer the bill in the next legislative session, said he heard compelling testimony that day that “the places where the high-volume charging equipment is succeeding, and it’s being built in, are areas where there’s a volumetric charge rather than a charge based on the maximum utilization during three minutes of the year.” 

Encouraging Charger Investment

Speakers at the hearing took differing positions on how to balance the need to stimulate charging site development with a sense of fairness in deciding who benefits from the installation, and so should help pick up the cost. 

The bill requires the new tariffs be shaped to avoid demand charges for commercial customers who own or operate electric vehicle charging systems. 

“Rates for electric distribution in the tariff shall be designed to encourage investment in faster, higher-powered electric vehicle charging facilities and shall include comparable costs per megawatt-hour for both higher-power and lower-powered direct current fast charging facilities,” the bill states. 

Jigar Shah, head of energy services at Electrify America, a charger development company, welcomed the requirement. He said demand charges are an “additional levy” that effectively mean commercial customers are treated differently than residential customers.  

Demand charges originally were designed to set rates on manufacturers who would have high, sustained peaks, rather than the short-term peak of a DCFC charger, Shah said. He said his company’s experience installing chargers has shown that a single charging point with four to six chargers at a New Jersey location could trigger demand charges of more than $350,000 a year. 

“The financial risk posed by this is cost-prohibitive to investment in further charging stations in New Jersey,” he said. 

Who Benefits From EV Use?

Other speakers expressed concern about the need for equity in who would pick up the tab if demand charges were not used. 

Doug O’Malley, director for Environment New Jersey, said the bill fails to clarify how costs will be distributed between customers and ratepayers. 

“We do believe that all customers benefit from electrification, not just those that are charging,” he said, in part by reducing electricity rates and curbing emissions. 

Because charging benefits the grid overall, he said, costs as a should be borne by the entire rate base. He urged the committee to take time shaping the bill, in part because “usage and consumption patterns for public fast charging is changing pretty significantly.” 

The state Division of Rate Counsel, in a Dec. 15 letter to the committee, also expressed concerns about where the cost burden might land. Brian O. Lipman, the division’s director, wrote that the bill “could unfairly shift costs from private businesses responsible for the costs of electricity to all other ratepayer customer classes through higher rates.” 

Demand charges are an important part of an electric utility’s rate design, intended to ensure it builds and maintains a “distribution system that is ready to serve the customer’s load at all times,” Lipman wrote.  

 “If demand charges are waived for certain customers who are putting the greatest demands on the grid, other customers, who use far less electricity, will ultimately pay for them through rate increases.” 

Lipman noted that the BPU, recognizing that demand charges play an “important role … in forming just and reasonable rates,” has taken steps to address the issue in connection with EV charger operation. Utilities offer “demand charge rebates” to some customers, and the BPU on Nov. 17 approved a package for Basic Generation Service that allows utilities to implement similar benefits to DCFC customers, he said. 

Kassandra Damblu of ChargeEVC New Jersey, an EV advocacy group, said the bill contains no consideration of “who pays for this discounted market structure.” In addition, she said, the rates should be flexible enough to reflect the usage patterns of the equipment over time. 

“As chargers get more use, the need for these types of rates decreases, so they should not be considered as a permanent solution, which is the case in this legislation,” she added.  

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Secretary Bose and Commissioner Danly Honored at Their Final FERC Meeting

FERC’s December meeting was the last open meeting for both its longtime Secretary Kimberly Bose and Commissioner James Danly, both of whom were honored for their service. 

Commissioner Danly came to FERC in 2017 ago and worked as its general counsel before being appointed commissioner and briefly was Chair near the end of President Donald Trump’s term. Danly also served as a U.S. Army officer in Iraq, where he earned the Bronze Star and Purple Heart. 

“Commissioner Danly, on behalf of staff and all the colleagues here, I have to say thank you for your service to FERC,” Chair Willie Phillips said at the meeting. “Thank you for your service to this nation. And thank you for significantly adding to the discourse here.” 

Danly’s output of dissents and concurrences was prolific, and his colleagues noted those legal arguments would outlive his tenure at FERC. 

Commissioner Allison Clements often was on the other side of the argument from Danly, but she held up the one joint dissent they agreed to in a waiver being sought by Michigan State University. 

“I think that’s one thing that we do share, which is a commitment to the law — and how we both interpreted that might be different — but I think he and his team have worked very hard over the years to expound upon that philosophy on the law,” Clements said. “And, certainly, there’s an impressive volume of writing to keep us on our toes and that will last beyond your time here at the commission.” 

Commissioner Mark Christie noted that before he came to FERC, he reached out to former members to get a sense of the job and he was warned to never get into an argument with Danly on legal issues because he always would win. 

“I probably never spent as much time arguing with somebody that I actually fundamentally agreed with,” Christie said. 

Christie called Danly an “American hero,” reminding the audience that recipients of the Purple Heart are injured in conflict. 

Danly, in what he said likely was the “longest speech” he ever gave at an open meeting (as a commissioner, he kept his words written more often than not), thanked his staff who made the thousands of pages of dissents he filed possible. 

“I will simply end with the observation that the Commission does immensely important work,” Danly said. “We have a profound responsibility in overseeing the gas and utility systems of America. And it’s been an honor of a lifetime to serve these capacities and agency for which I have genuine affection.” 

That work would grind to a halt without the Office of the Secretary, which handles the voluminous paperwork the regulatory agency produces and submittals it must process. Since Bose took the secretary job in March 2007, anyone who has spent time perusing FERC’s “e-library” has seen her name everywhere. 

Danly said the Office of Secretary is the linchpin of FERC’s work, and actually puts out words on paper that people have to read in order to implement its rulings. 

“Having a secretary who has the judgment that she has and the clarity of her office’s mission that Kim has had, and also, the fact that there is not a single person that’s ever encountered here that doesn’t think that she is acting with the best of goodwill and perfectly honorable intentions that is a reassurance that every commissioner has to have,” Danly said. “And ‘O-Sec’ is an institution that is utterly reliable and unimpeachable and that is because of Secretary Bose.” 

FERC’s Secretary Kimberly Bose makes rare impromptu comments at the end of her last meeting. | FERC

Bose has been at FERC for 37 years, starting off as a legal intern, and in that time has gotten pretty much every award the commission gives to its staffers, Phillips said at the open meeting. He gave her two more: a Career Service Award and the Chairman’s Medal. 

Both Bose and Phillips attended Howard University School of Law, and he said she has had a major impact on its alumni and Black attorneys generally. 

“What I appreciate about Secretary Bose is the example that she has set for members of the Howard University community, in particular attorneys of color throughout the energy bar,” Phillips said. “If you wrote to the commission, any type of application, any kind of filing, you directed that to Secretary Bose.” 

That means every FERC lawyer knew her by name. Phillips added that she was a good mentor for him personally. 

Clements called Bose an inspiration, noting that when she started at FERC decades ago there was nobody at the commission’s dais (where commissioners and senior staffers sit) who looked like her. 

“Absolutely to your point, Commissioner Clements, when I came in as a legal intern … I never did think that someone would sit at this horseshoe that looked like me, and even more so I never thought that we would see a Black chairman of the commission,” Bose said. “So, I am so grateful that you are here, and I am so grateful that I was here to see that.” 

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FERC Upholds MISO Ban on Renewables Supplying Ancillary Services

FERC has reaffirmed that MISO can exclude renewable resources from providing ancillary services in its markets.

The commission rejected the Solar Energy Industries Association’s request for rehearing on two related FERC dockets allowing MISO to block renewable energy’s participation in its ancillary services market (ER23-1195-002). The American Clean Power Association, Clean Grid Alliance, Natural Resources Defense Council, Fresh Energy, Union of Concerned Scientists and Sierra Club joined SEIA on one of the two requests for rehearing.

Dec. 19’s denial continues a pattern of FERC insisting the output from renewable energy isn’t on equal footing with that of traditional resources because pervasive transmission congestion keeps renewables’ ancillary services from being economically deliverable to market. (See FERC Blocks Solar Group’s Contest of MISO Ban on Renewable Ancillary Services; FERC: MISO Can Ban Intermittent Resources from Providing Ramp.)

The group of clean energy groups argued FERC erred in its original judgment because it extended the exclusion to hybrid resources.

The commission disagreed. It said the arguments that hybrid resources have distinct characteristics from standalone wind and solar resources “lack specificity and are not sufficient to support an undue discrimination claim.”

“SEIA has not demonstrated that hybrid resources … will not be subject to the same deliverability issues MISO has identified for standalone wind and solar,” the commission said.

FERC pointed out that the MISO tariff allows hybrid resources to register their wind or solar portion and on-site storage together as a single dispatchable intermittent resource or separately in the markets.

The commission also said the clean energy groups did not argue on rehearing that standalone wind and solar resource are inappropriately barred from supplying ramping needs. FERC said the groups might now be hoping for a separate market designation for hybrid resources.

“To the extent that [the] clean energy coalition now seeks new market participation rules for ‘integrated hybrid sources,’ such a challenge is outside of the scope of this … proceeding,” FERC wrote.

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DOE Announces $890M in IIJA Funds for CCS Demonstration Projects

The Department of Energy is preparing to award up to $890 million to three carbon capture and sequestration (CCS) demonstration projects located at existing natural gas- and coal-fired power plants, with the goal of avoiding up to 7.75 million metric tons (MMT) of carbon dioxide emissions per year.

Announced on Dec. 14, the three projects are the first to be selected as part of DOE’s Carbon Capture Demonstration Projects Program, with $1.7 billion from the Infrastructure Investment and Jobs Act to fund at least six CCS projects at both power plants and industrial facilities that do not produce power.

According to the funding announcement, originally issued in February, DOE was looking for projects that would provide “transformational domestic, commercial-scale, integrated CCS demonstration … designed to further advance the development, deployment and commercialization of technologies to capture, transport (if required) and store CO2 emissions.”

The three projects selected are:

    • The Baytown Carbon Capture and Storage Project in Baytown, Texas, near Houston, is a natural gas, combined cycle plant, owned by Calpine, and is slated to receive up to $270 million. The CCS technology to be used has been developed by Shell and would sequester the captured CO2 in underwater saline aquifers on the Gulf Coast. The project could use a greywater cooling system that recycles wastewater and would sequester an estimated 2 MMT per year. The primary off-taker for the power produced with CCS would be Covestro, an industrial manufacturer of plastics.
    • Project Tundra, located near Center, N.D., near the state capital of Bismarck, would use Mitsubishi CCS technology to capture up to 4 MMT of CO2 at the Minnkota Power Cooperative’s Milton R. Young coal-fired power plant. The CO2 would be stored in “saline geologic formations” sited beneath or near the power plant. The project could receive up to $350 million in federal funds.
    • The Sutter Decarbonization Project in Yuba City, Calif., another Calpine natural gas combined cycle plant, would use yet another CCS technology developed by Ion to sequester up to 1.75 MMT of CO2 per year. According to DOE, the project also would be the first in the world to use an air-cooling system, rather than water, responding to “a critical concern of the local community and an imperative to further deployment of CCS in the arid Western U.S.” The pipeline for the project would run within or parallel to an existing natural gas pipeline right of way. Federal funding could be up to $270 million.

None of the CO2 captured by the projects would be used for enhanced oil recovery, in which captured CO2 is pumped back into low-producing oil wells to push out more oil. Awardees are required to provide at least 50% of project costs, according to the funding announcement.

DOE is funding three CCS demonstration projects at power plants in California, North Dakota and Texas. | DOE

CCS Normalized?

Immediate reactions from awardees and CCS industry groups framed the projects as critical for the U.S. to reach its goals for greenhouse gas emission reductions.

“We’re grateful that the Department of Energy recognizes the importance of developing carbon-capture systems and is positioning the United States to be a leader in the advancement of this critical clean energy technology,” Minnkota CEO Mac McLennan said in a statement. “Innovation is our path forward through the energy transition.” Project Tundra could “help pave the way toward a future where electric grid reliability and environmental stewardship go hand in hand.”

Citing Baytown’s ability to provide firm, dispatchable and “non-duration-limited” power, Caleb Stephenson, Calpine executive vice president of commercial operations, said similar natural gas plants “will be part of our energy infrastructure for the foreseeable future, and now with CCS technology, we can decarbonize them.”

Baytown and the Sutter Decarbonization Project are part of Calpine’s pipeline of 11 CCS projects, according to DOE.

Jessie Stolark, executive director of the Carbon Capture Coalition, hailed DOE’s choice of “geographically diverse projects [that] will demonstrate best-in-class methods to capture carbon at various power generation settings … providing further insight into the continued development and deployment of carbon capture at this critical juncture of climate mitigation.”

Stolark and others point to reports from the International Energy Agency and the U.N. Intergovernmental Panel on Climate Change, both of which have said carbon capture will be essential for the world to cut emissions and limit climate change to 1.5 degrees Celsius.

While acknowledging that CCS and other carbon-management technologies are not “a silver bullet” for reducing emissions, Stolark said they should be part of a broader set of solutions and receive “sustained legislative and regulatory support.”

DOE estimates the U.S. will need to capture and sequester between 400 million and 1.8 billion MT of CO2 annually to meet President Joe Biden’s target for economywide net-zero emissions by 2050. But carbon sequestration projects require a special permit from EPA to inject carbon into geologic formations, such as caverns or aquifers needed for permanent storage. As of Dec. 8, EPA is considering 61 applications for these Class VI permits; it has issued only two.

Getting to ‘Go/No-go’

Speaking during an online briefing Dec. 18, Kelly Cummins, acting director of DOE’s Office of Clean Energy Demonstrations (OCED), said that, as is the case with most DOE award selections, CCS projects in this first round of awards are not guaranteed federal funding. Rather, they will begin negotiations with the department for a phased-in release of the money over four planning and development stages, she said.

“During the negotiations process, OCED will discuss how the selectees can make their projects more robust from a technical, financial and community benefit standpoint,” she said. As part of any potential award, “OCED and the project teams will enter into a cooperative agreement, which gives OCED substantial involvement throughout the public-private partnership.”

Between each phase of planning and development, “DOE will assess the project’s progress, and we’ll make a decision about whether the project should receive additional funding. We call this a ‘go/no-go’ review,” she said.

Actual installation and construction of the projects could take three to six years, Cummins said, with ramp-up and operation adding an additional two to four years to timelines. Projects also may have to undergo an environmental review under the National Environmental Policy Act.

Each project also must have a community benefits plan that may include labor agreements with unions and training programs and internships for local students. Under Biden’s Justice40 Initiative, 40% of project benefits have to go to low-income, disadvantaged or underserved communities.

The Sutter Decarbonization Project, for example, is negotiating a project labor agreement and has set “a 10% diverse supplier spend goal,” targeting small businesses owned by women and people of color, according to DOE. The Lawrence Berkeley National Laboratory would serve as an independent third party to monitor the project’s implementation of its community benefits plan.

Next steps will include a series of virtual community information sessions for each project in early January, Cummins said: Project Tundra on Jan. 9, Baytown on Jan. 10 and Sutter Decarbonization on Jan. 11.

A second round of funding is expected “in the future,” Cummins said, to meet the requirements in the IIJA. The law calls for the CCS demonstrations projects to be located at two natural gas-fired plants, two coal-fired plants and two industrial sites.

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FERC’s CIP Report Finds Fewer Issues Again

FERC staff’s audits for compliance with NERC’s Critical Infrastructure Protection (CIP) standards this year produced the fewest recommendations for improvement yet, indicating that North American utilities’ cybersecurity practices largely meet the standards’ mandatory requirements. 

As in previous years, however, the commission identified several aspects in which registered entities’ compliance needs improvement, as well as voluntary actions to improve cybersecurity protections in general. 

FERC has been performing the CIP audits since 2016. Each audit covers the preceding fiscal year, which runs from Oct. 1 to Sept. 30. Audits comprise “data requests and reviews, webinars and teleconferences, and virtual and on-site interview sessions,” FERC said in the audit report. 

Auditors spoke with entities’ subject matter experts, along with employees and managers responsible for CIP compliance tasks, and watched as personnel demonstrated the utilities’ operations. Audits also included reviews of relevant documentation, remote field inspections and observations of relevant cyber assets in operation. Staff from NERC and the regional entities participated in the audits alongside FERC personnel. 

Details about the audits, such as how many audits were performed and which utilities were selected for examination, were not disclosed. 

This year’s report included four lessons learned from the audits, relating to seven specific CIP standards. This is the fewest lessons learned since the commission began issuing the annual reports. Last year’s report produced five lessons learned, after 14 the previous year. (See FERC Report Finds CIP Issues Declining.) 

The first lesson concerns identification and categorization of grid cyber systems and associated cyber assets. Requirement R1 of CIP-002-5.1a (Cybersecurity — BES cyber system categorization) mandates that registered entities identify cyber systems and assets whose “loss, compromise or misuse … could [impact] the reliable operation of the” electric grid. The report’s authors observed such identification “forms the foundation of the CIP … standards [because] miscategorization … can lead to the application of inadequate cybersecurity controls, or no controls at all.” 

Utilities’ procedures for identifying applicable cyber systems were “generally … strong,” FERC staff found; however, auditors did find some cases in which systems were not categorized properly. In particular, some entities did not correctly classify hypervisors — software used to operate virtual machines — by the highest impact level of the virtual assets they manage. In addition, medium-impact cyber systems at some utilities were not identified as critical to derivation of interconnection reliability operating limits and associated contingencies. 

Incident Notification Challenges

FERC’s next lesson learned relates to cybersecurity incident notification, the subject of several CIP standards. 

CIP-008-6 (Cybersecurity — incident reporting and response planning) requires entities with medium- and high-impact cyber systems to notify the Electricity Information Sharing and Analysis Center (E-ISAC) in the event of a reportable cybersecurity incident, as identified in the standard. CIP-003-8 (Cybersecurity — security management controls) mandates that entities with low-impact cyber systems determine whether incidents at such systems compromised or disrupted reliability tasks and to notify the E-ISAC if so. 

The commission found several incidents that entities did not properly identify or report to the E-ISAC. In one case, the entity discovered malware on a cyber system that it did not report as required by its incident response plan because the entity determined it was not compromised. 

Another entity found malicious code on an installer in a cyber system’s recycle bin, a situation not covered by its incident response plan. The utility decided its system had not been compromised and no report was necessary; however, FERC staff said the malware still had “potential to perform malicious actions” and CIP-008-6 required such incidents to be reported. 

FERC’s report emphasized that unreported incidents make it harder for grid operators to identify security risks, leading to compromised situational awareness for all entities. Recommendations included “developing more holistic criteria” for incident identification and improving the processing and investigation of CIP-related events. 

The next lesson involves restriction of inbound and outbound access permissions as required in CIP-005-7 (Cybersecurity — electronic security perimeters). Requirement R1 mandates that utilities deny all access attempts that lack such permission. 

Audit staff found that the standard was “generally” followed, but in some cases, entities either did not restrict access permissions, did not document the reason for granting access or both. Staff observed that “allowing [traffic] throughout the network without valid reason and oversight could lead to possible security compromise.” Recommendations included reviewing access configurations on a quarterly basis to ensure access is denied by default and all exceptions are documented. 

Finally, the auditors noted that some entities’ supply chain risk management plans had not been updated with responses to identified risks in contracts negotiated with vendors after the effective date of CIP-013-1 (Cybersecurity — supply chain risk management). 

While the standard (which has since been replaced with CIP-013-2) does not require entities “to renegotiate or abrogate existing contracts,” FERC staff noted that inadequate risk assessment can affect reliable grid operations if entities use vulnerable products. Staff urged entities to review contracts that have not already been examined for potential risks — whether negotiated before or after the effective date of CIP-013-1 — and ensure that their plans address such risks. 

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Maryland Adopts California’s Advanced Clean Trucks Rule

Maryland last week became the 10th state to adopt the Advanced Clean Trucks rule, which sets targets for the delivery of zero-emissions medium- and heavy-duty vehicles that gradually increase every year.

The rule was pioneered in California, which has authority under the Clean Air Act to set its own standards for vehicles that other states can adopt. It was published in the Maryland Register on Dec. 15 and will become effective on Dec. 25.

The annual increases will end in 2035, at which point zero-emission vehicles would need to make up 55% of pickup truck and van sales, 75% of rigid/box truck sales and 40% of tractor-trailer sales.

“Transportation is the largest source of climate pollution in Maryland and a leading source of toxic air pollution that is hazardous to human health,” Maryland Sierra Club Director Josh Tulkin said in a statement. “Adopting strong clean vehicle standards will help put the state on track to meet its ambitious climate goals, reduce dependence on fossil fuels and improve public health.”

While they represent just 9% of registered vehicles, medium- and heavy-duty trucks and buses generate 39% of smog-forming nitrogen oxide (NOx), 48% of particulate matter (PM2.5) pollution and 21% of greenhouse gas emissions from all on-road vehicles in the state.

A group of businesses and environmentalists urged the state to start implementing the rule as soon as possible — starting with model year 2027 cars. The benefits of lower pollution from the rule are expected to create $19.8 billion in health benefits over the next three decades, avoid 1,800 premature deaths, 46,800 asthma attacks and 231,200 lost workdays, according to analysis by the American Lung Association.

Maryland’s General Assembly voted to adopt the rule this spring, and the Clean Trucks Act of 2023 was signed by Gov. Wes Moore (D) in April.

“The transition to electric fleets is beginning to take shape. State policies like the ACT rule create a foundation for an electrified future — one where a diverse array of electric vehicles are driving on our nation’s roads and a robust charging network is built out from coast to coast,” Siemens’ Ryan Dalton said in a statement. “By adopting the ACT rule, Gov. Moore has again established Maryland as a leader in America’s green economy — producing lower carbon emissions and less pollution — all while creating equitable economic benefits for its communities.”

The Swedish furniture firm IKEA said it’s committed to getting 100% zero emissions on its home deliveries, but it needs policies to help hit that goal.

“The ACT rule is vital to helping Maryland companies meet our climate goals to move away from dirty deliveries and toward a cleaner and more just economy,” said Steven Moelk, IKEA manger of retail U.S. fulfillment project implementation.

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Former Employee Details Failures at Entergy’s Grand Gulf

A former employee of Entergy’s Grand Gulf Nuclear Station testified last week that he witnessed mismanagement by plant supervisors and was fired for refusing to revise audits documenting problems.

Jairus Greene testified Dec. 12 at the request of the Louisiana Public Service Commission, which is seeking millions in refunds from Entergy over alleged mismanagement of the 1,443-MW plant (EL21-56).

Testifying at the law offices of Stone Pigman Walther Wittmann in New Orleans, Greene said he witnessed poor engineering decisions, frequent reactor trips and scrams — or the sudden shutting down of a nuclear reactor — exemplified by Grand Gulf’s unusually low capacity factor. At one point, Greene said he couldn’t recall the length of individual outages because trips were commonplace. From 2016 through 2018, Grand Gulf ran at about a 55.5% capacity factor when other nuclear plants in the nation averaged over 92%, according to data from the U.S. Energy Information Administration.

Entergy says it has improved the plant’s operations, touting its 95% capacity factor in 2021. The utility also said Grand Gulf attained the highest rank in the Nuclear Regulatory Commission’s performance matrix in 2022.

Greene, who has more than 20 years’ experience in nuclear capital projects and cybersecurity, worked at Grand Gulf for about three years before he was fired in April 2022.

Greene spoke carefully during his deposition, acknowledging he lacked first-hand knowledge of some of what he reported, which came from other employees.

He said he believed security personnel at the plant worked shifts that were too long and they had no time for bathroom breaks. Employees found human excrement in some areas of the plant, he said.

He said he was aware of Grand Gulf’s poor reputation when he was hired. He “was kind of ashamed to admit” he worked in “a place like this,” he testified.

Greene said Grand Gulf leadership choose not to conduct engineering hold points — a pause on construction activities until an inspection is passed — as part of a turbine controls project in 2020.

Greene said he was concerned that some equipment considered critical digital assets at other reactors he worked at wasn’t considered such at Grand Gulf.

He also said there seemed to be numerous maintenance deferrals throughout his employment.

Greene said he took his concerns over pressures to issue more favorable audit findings and a chilled work environment to the Nuclear Regulatory Commission. 

Greene said he and other employees would meet informally at a nearby supermarket to discuss their concerns over the plant. Some colleagues left their positions to avoid compromising their integrity, he said. 

Greene said shortly after he wrote a memo on security lapses, he found his security clearance revoked. Shortly after, he was fired. 

However, Greene said he still believes in nuclear power though some utilities don’t operate plants reliably. 

In March, Greene filed a federal lawsuit against Entergy in the Southern District of Mississippi alleging he was fired for refusing to falsify safety reports (5:23-cv-00016). He contends he used legally prescribed THC derivatives to treat severe glaucoma and that Entergy used the pretext of a failed drug test to fire him in retaliation. He said he has never used marijuana.

Entergy spokeswoman Mara M. Hartmann declined to comment Monday on Greene’s allegations, citing “pending legal matters.” 

“Entergy is committed to the safe, secure and reliable operation of our plants in compliance with all applicable NRC regulations, including the NRC’s fitness-for-duty requirements,” she said. “We are proud that our Grand Gulf Nuclear Station has all green, or best possible, performance indicators in the regulatory performance matrix.”

Greene’s deposition came in a long-running dispute between Entergy and state regulators. Entergy subsidiary System Energy Resources Inc. operates and owns 90% of Grand Gulf and sells the plant’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.

The Louisiana PSC maintains that ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers.

FERC has ruled against Entergy on some tax maneuvers and lease payment collections in another proceeding, though the exact amount owed is still up for debate. Louisiana regulators are asking FERC to fine Entergy $1 million a day for refusing to pay the refunds. (See Latest FERC Order on Grand Gulf Nuclear Plant Ambiguous on Refund Amount.)

Last month, Louisiana Public Service Commissioner Davante Lewis told The Times-Picayune/The New Orleans Advocate that it seems “Entergy is playing a legal maneuver that basically tries to bully us and wear down the clock.”

In October, the Arkansas Public Service Commission accepted Entergy’s $142 million offer to settle its claims, a year after turning down the same offer. Entergy estimates it has already refunded $50 million of that amount to Arkansas, according to a filing with the U.S. Securities and Exchange Commission.

Mississippi settled its claims related to Grand Gulf in 2022, accepting a $300 million refund. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.) 

During a third-quarter earnings call last month, Entergy CEO Drew Marsh said the deals with Arkansas and Mississippi resolve approximately two-thirds of the financial risks related to lawsuits over Grand Gulf. Marsh also warned that reaching a resolution in the FERC cases could take up to two years. 

Grand Gulf, the largest single-unit nuclear plant in the U.S., began commercial operations in 1985. In 2016, the NRC granted the plant a 20-year license extension, allowing it to operate through 2044.