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November 13, 2024

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Report Questions Dominion IRP’s Call for New Natural Gas Plants

The Chesapeake Climate Action Network (CCAN) Action Fund on Thursday released a report arguing that Dominion Energy can meet growing demand for electricity in its territory with clean energy instead of building new natural gas plants, as it has proposed. 

The report, which the environmental group commissioned from the consultancy Gabel Associates, pushes back against Dominion’s pending integrated resource plan that was filed with the Virginia State Corporation Commission this spring. (See Enviros Pan Dominion Integrated Resource Plan.) 

“Unfortunately, Dominion’s plan is not compliant with laws passed by the General Assembly in 2020 and 2021, including the Virginia Clean Economy Act and regulatory directives to account for economic externalities associated with air pollution,” the report said. “As an example, Dominion intends to build 1,000 MW of new gas-fired generation capacity in Chesterfield County by 2027 even though doing so will generate more than 2 million tons of additional carbon emissions each year.” 

The utility expects peak demand to grow by 2.32% and overall energy consumption by 3.25% annually, which the report said could be met while retiring coal- and gas-fired power plants using PJM’s generator replacement process to avoid queue delays, adding battery storage at existing sites, expanding behind-the-meter solar and increasing energy efficiency and demand response. 

“Dominion has a chance to cut costs for Virginians by $28 billion and slash greenhouse gas emissions by 52 million tons over the next decade without compromising system reliability simply by switching out old fossil fuel plants for new solar panels and battery systems,” Gabel Associates Vice President Adrian Kimbrough said. 

Dominion’s load growth projections are based on assumptions including significant growth in data centers in its territory, though the report said it is unclear if this growth is made up of projections or actual contractual arrangements. The projections also include efficiency and demand-side management, but the report questions whether those could be higher and lead to lower load growth. 

The IRP has already seen proceedings in the SCC; in a brief filed in late October, Dominion said it had picked a middle path of data center growth out of three scenarios, which was reviewed by PJM, as the commission has required in the past. The first five years of that forecast are more certain than the later 10 covered in the IRP, the utility said. 

CCAN and Gabel proposed an alternate resource plan, which would hold constant the current and contracted renewables Dominion has while accelerating the retirement of 8.5 GW of fossil fuel capacity that has operated for 20 years. The retired capacity would be replaced with a range of solar, including the company’s own utility-scale projects, behind-the-meter resources and contracts with third-party developers. Dominion would also need to add battery storage to sites of existing and planned renewable energy generators using PJM’s Surplus Interconnection Queue. 

The report does not get into specifics for what should replace the retiring capacity and avoided new fossil plants because it is meant to provide a high-level alternative to Dominion’s proposals. 

CCAN said the report bolsters the argument that a proposed 1,000-MW natural gas plant in Chesterfield is not needed. The group and some local citizens are opposing the plant’s construction. 

Dominion told the SCC last month that dual-fuel combustion turbines like the one proposed for Chesterfield are “currently the most cost-effective and reliable resource” to meet a future long-duration winter event or capacity shortage. Other parties including Advanced Energy United and the Sierra Club have pushed back on its plans for new gas plants. 

“Reliability is paramount to the company, and the significant increase in the load forecast, coupled with events like Winter Storm Elliott, have highlighted the need for dispatchable generation and the reliability benefits of natural gas units” to serve the company’s customers, Dominion said in its filing. 

Dominion said the IRP is not the proper venue to litigate the need for specific power plants, as the SCC does not approve or reject any actual plants in such proceedings. The firm will have to apply for a certificate of need and public necessity for specific plants, which is where the need for actual powers is properly debated, it said. 

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RTO Officials Warn of ‘Messy Transition’ at NARUC Annual Meeting

LA QUINTA, Calif. — As pressure grows to decarbonize the electricity sector, grid operators increasingly are grappling with how to coordinate the retirement of traditional resources with the introduction of new non-emitting resources — all while ensuring reliability and affordability.

Challenges of the grid’s transition was a running theme of the discussions among utility regulators and power industry stakeholders at the National Association of Regulatory Utility Commissioners’ Annual Meeting in the Southern California desert Nov. 12 -15.

“In these discussions you get the question of what keeps you up at night,” MISO CEO John Bear said. “The transition … is probably the biggest concern that we have.”

In a Nov. 14 panel, RTO/ISO executives identified the litany of challenges their organizations face as they attempt to retire thermal generation and integrate renewables onto the grid.

“We have to keep the lights on and keep the power affordable through the transition,” PJM CEO Manu Asthana said. “The big difference is the new resources that are coming on are not predictable in the same way that the old resources were.”

With the retirement of thermal generation comes the challenge of ensuring there are enough dependable resources to fill the gap when weather-dependent renewables can’t serve load. The introduction of new technologies has been slow, and if traditional resources are retired too soon, grid operators fear the worst.

“That’s probably one of my biggest concerns, is that we will let these resources that we have, that we use today, retire and not have the replacement resources come in time,” Asthana said. “We just can’t let that happen.”

Asthana pointed out that PJM is on track to retire about 40 GW of resources by 2030; Calpine’s Joseph Kerecman told RTO Insider that may be an understatement. (See PJM Whitepaper to Highlight Future RA Concerns.)

The solution, the CEOs said, is to keep some traditional methods of generation, like natural gas plants, on the grid as long as possible in combination with renewables to ensure reliability.

“There’s a lot of pressure to not build gas infrastructure, but gas is the marginal fuel in our markets,” Asthana said. “We’re approaching this intersection where we know we have to decarbonize the system, but I think we are at risk of not doing so in an orderly fashion.”

NERC CEO Jim Robb emphasized another solution to make a smoother transition: getting better standards in place for inverter-based resources. He noted that while inverter-based resources are currently “grid-following,” they will have to form the grid when they start making up 40 to 60% of the generation mix.

“That’s the path toward a carbon-free grid: having grid-forming technology through power electronics. But we’re not there yet,” he said.

Greater Gas-electric Coordination Needed

Robb said the electric industry is the largest consumer of natural gas, and with the increasing demand for electrification comes a greater need for coordination between the electric and gas sectors.

“If we continue to just build out the electric sector, but we’re not paying attention to the fuel infrastructure behind it, we’re going to run into a lot of issues,” Robb said.

During a Nov. 15 panel, commissioners, regulators and strategists emphasized the need to view and operate the grid as a single entity.

“There’s two separate grids right now,” said Jason Ketchum, vice president at ONE Gas, a Oklahoma-based utility that also serves customers in Texas and Kansas. “There’s a gas grid, and there’s an electric grid, and we need to start talking about the energy grid.”

Diverting from many of the week’s climate-focused conversations, Ketchum emphasized the importance of listening to the customer and recognizing that people in some communities may not have the interest or capability to moderate their lifestyles in the interest of burning less gas.

“We serve a pretty wide geographic area, and a lot of our communities are different,” Ketchum said. “Some are more focused on environmental issues; others are more focused on affordability.”

Georgia Public Service Commissioner Tricia Pridemore, who moderated the panel, asked “if the answer to all of this” was to build more pipelines.

Not necessarily, Ketchum said: Focus on delivering whatever the best asset is to the customer in any given area. But he also emphasized gas as an important economic driver.

“There’s a lot of parts of our region that don’t have gas that can’t grow economically,” he said. “It’s a great opportunity to locate assets in areas that can really help out those communities.”

Getting into GEAR

North Dakota Public Service Commissioner Julie Fedorchak, who was elected NARUC president during the conference, announced a new initiative called Gas-Electric Alignment for Reliability (GEAR).

Led by Pridemore, NARUC’s newly elected vice president, GEAR will bring together a task force of regulators, utilities, grid and pipeline operators, and gas producers and suppliers to help better coordinate the gas and electric industries. Energy officials are hopeful GEAR will initiate meaningful progress toward greater gas-electric coordination to meet the country’s reliability and clean energy needs.

“This is going to be a messy transition, almost guaranteed,” PJM’s Asthana said. “But I’m almost certain we’re going to solve this problem.”

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FERC Optimistic About Energy Markets This Winter

Higher-than-average temperatures in parts of the U.S. could reduce electricity and natural gas demand and help prevent energy shortfalls this winter, FERC staff said in the commission’s 2023-2024 Winter Energy Market and Electric Reliability Assessment, released Nov. 16.

However, the possibility of one or more prolonged cold weather events, along with drought and wildfires continuing through the season, means significant reliability risks remain, NERC staff told commissioners at FERC’s open meeting.

The concern was stated most bluntly by Mark Lauby, NERC’s chief engineer, who spoke after Commissioners Allison Clements and Mark Christie responded to FERC staff’s presentation of the report. Although Clements noted the mild weather forecast and natural gas futures prices as “areas for optimism,” and Christie said “hopefully we’ll get through [winter] with some luck,” Lauby professed to being “taken aback” by the commissioners’ comments.

“I don’t like to plan on hopes and dreams,” Lauby said, noting NERC’s own recently released 2023 Winter Reliability Assessment warned that much of the North American electric grid faces elevated or high risk of energy shortfalls in December, January and February. (See NERC: Grid Risks Widespread in Winter Months.) “And even if, in fact, we have an average winter, that doesn’t mean we won’t have a cold spell during the winter. … That’s the kind of stuff that keeps me up at night.”

Mild Temperatures in North, West

FERC’s assessment cited the National Oceanic and Atmospheric Administration’s seasonal temperature outlook, which predicted that a strong El Niño effect in the Pacific Ocean will bring warm temperatures to the West Coast, leading to a strong likelihood of higher-than-normal temperatures across the northern U.S. The Southern states are equally likely to experience below-average temperatures as they are to experience above-average ones.

The likelihood of higher temperatures during the winter months — particularly in colder regions of the country — suggests less energy will be needed for heating and a lower likelihood of insufficient gas for both heating and electricity, FERC’s report said. But the assessment also noted that NOAA’s forecasts “do not include the probability of extreme cold weather events,” which can affect energy supply and demand in unforeseen ways, and that “below-freezing temperatures can stress critical infrastructure … especially natural gas facilities.”

Drought conditions are also expected to persist in the central U.S. through winter, potentially causing problems for hydropower plants in the north-central U.S. and lack of fresh water for thermal plants in the south-central areas. Similar conditions are predicted for the Pacific Northwest as well. In addition, the Canadian wildfire season — including several large existing fires — is now expected to continue into winter, which could affect regions in the U.S. with connections to Canada such as WECC, MISO and ISO-NE.

Drops Expected in Gas, Electricity Prices

FERC’s report said natural gas prices are expected to be lower this winter than in previous years, despite rising demand, thanks to growing production and high natural gas storage levels. But while market fundamentals “indicate adequate availability of natural gas at the national level,” local fuel availability may still be affected by “regional constraints.”

According to the assessment, the predicted average natural gas demand is expected to reach 122.4 Bcfd, 4% over last winter and 7.2% more than the previous five-year average. Electricity generation constitutes about a quarter of this demand, at 32 Bcfd, with residential and commercial use making up the largest share, at 42.3 Bcfd. The biggest growth in demand is from net natural gas exports, which are projected to average 13 Bcfd this winter, up 21% from winter 2022-2023 and 62% from the previous five-year average.

Gas futures prices Nov. 1 were lower than the final settled futures prices for last year at all of the trading hubs cited in the report, and at several hubs, they were below the previous year’s final settled prices as well. FERC’s report attributed last winter’s soaring prices to the impact of Winter Storm Elliott in late December.

Wholesale electricity prices are also projected to decline at most major pricing hubs compared to last winter, the assessment said, with the greatest difference seen in the West, where last year’s record high gas prices contributed to higher electricity prices as well. Declines of at least $5/MWh are also expected in the Southeast, NYISO and PJM.

In SPP, prices are expected to increase from $37.81 on average last winter to $38.21 this winter. However, SPP is projected to have the lowest wholesale electricity prices on average of any region, the report said.

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FERC Accepts Basin Tariff Revisions, Sets for Hearing

FERC last week accepted SPP’s proposed tariff revisions for Basin Electric Power Cooperative’s formulate rate template, suspending them for a nominal period, effective Nov. 14, subject to refund, and established hearing and settlement judge procedures. 

The commission said in its Nov. 13 order that its preliminary analysis indicated the proposed revisions have not been shown to be just and reasonable and that they raise issues of material fact more appropriately addressed in the hearing and settlement judge procedures (ER23-2836). 

FERC did find that a 50-basis point adder it previously granted Basin Electric for RTO participation still was appropriate, given Basin Electric’s continued membership in SPP. It said that the cooperative’s return on equity (ROE), inclusive of the adder, must remain within the zone of reasonableness during the hearing and settlement judge proceedings. 

SPP filed the tariff changes in September after FERC said Basin Electric became subject to its jurisdiction when it readmitted Tri-State Generation and Transmission Association as a non-exempt Class A member in November 2019. Basin Electric proposed to revise its template to reflect a base ROE of 9.69% and the 50-basis point adder for its SPP membership and calculated an 8.65%-11.12% composite zone of reasonableness. 

The cooperative also proposed to revise its template to reflect a capital structure of 48.22% equity and 51.78% long-term debt, based on the weighted average capital structure of transmission owners across the SPP region. Basin Electric claimed that because it is the largest non-governmental transmission owner by capitalization in SPP’s Upper Missouri pricing zone, it is appropriate to rely on the weighted average capital structure used in all SPP transmission owners’ formula rates. 

The proposed ROE and capital structure would result in an increase to the 2022 annual transmission revenue requirement of $4.68 million, Basin Electric said. That is about 4% under its 2022 ATRR under the existing template. 

Black Hills Settlement OK’d

FERC on Nov. 16 approved an uncontested settlement of Black Hills Colorado Electric’s proposed tariff revisions to transition from a stated transmission rate to a forward-looking formula rate for transmission service (ER22-2185). 

The commission last year accepted and suspended, subject to refund, the utility’s proposed revisions, setting the proceeding for hearing and settlement judge procedures. An administrative law judge approved the settlement with intervenors Tri-State and Arkansas River Power Authority in September and certified the agreement to FERC on Oct. 4. 

Commission trial staff supported the settlement, saying its approval “will resolve all issues set for hearing.” They said the agreement provides “significant benefits to ratepayers,” pointing to an ROE of 9.8% that was lower than the filed ROE of 10.44%. 

Staff also said a fixed capital structure of 47% equity and 53% debt is “both reasonable and preferrable” to the company’s as-filed proposal for variable capital structure. A three-year moratorium of “key components of the formula rate” avoids further litigation, they said. 

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MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant

CARMEL, Ind. — Weeks after the nearly $2 billion Joint Targeted Interconnection Queue (JTIQ) transmission portfolio was awarded a $465 million Department of Energy grant, MISO and SPP are switching their proposed cost allocation for the projects.

Now, all costs of the JTIQ portfolio should be assigned to interconnection customers, MISO and SPP have agreed. The new cost allocation will replace the RTOs’ previously proposed 90% assignment to interconnecting generators with the remaining 10% to load.

The RTOs have further said all operations and maintenance costs on the projects will be borne by the constructing RTO’s load.

Last month, DOE announced the JTIQ portfolio will receive $464.5 million from the department’s Grid Resilience and Innovation Partnership program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

MISO Director of Resource Utilization Andy Witmeier said MISO, SPP and states are in the middle of negotiations with DOE before they can receive the money.

Speaking at a Nov. 15 Planning Advisory Committee meeting, Witmeier said the grant will help get the JTIQ portfolio online “to the benefit of generators waiting to interconnect.” And he said a more simplified cost allocation likely will help move the projects across the finish line, even though MISO and SPP had settled on the 90/10 allocation almost a year ago.

“This is what MISO and SPP believe will have the most success in getting approved,” he said.

Witmeier characterized the change in direction on cost allocation as a “small pivot.” He said MISO always would have used the grant money to apply for the load’s share of project costs first, and the $464 million grant more than takes care of the tab load would have picked up under the original cost allocation proposal.

Witmeier said MISO and SPP concluded DOE’s funding can address rate complexities the 10% allocation to load will introduce in how costs will be spread across load and how operations and maintenance costs will be handled. He said using a 100% allocation ensures entitlements are assigned to the constructing region and reduces risk that load in one RTO is supplementing transmission in the other in the unlikely case not enough generation shows up to fund the lines.

Witmeier said the 100% method is a “much simpler rate design, if you don’t have load in that calculation.”

He also said the 100% allocation to generators matches SPP’s existing interconnection upgrades allocation and allows MISO and SPP to approach FERC with a “consistent approach.”

“The 100% is a small shift for MISO, but the 90/10 was a big shift for SPP,” he said.

In MISO’s individual queue process, interconnection customers bear 100% of interconnection costs except when network upgrades are 345 kV or higher, when the 90% to interconnection customers, 10% to load allocation kicks in.

In an email to RTO Insider, SPP confirmed the new rate design will be a better fit with its current cost allocation for generator interconnection projects.

Xcel Energy’s Carolyn Wetterlin said her utility agrees with the change. She said a 100% allocation will result in a “cleaner filing” to FERC and less costs borne by ratepayers in MISO and SPP.

However, the Coalition of Midwest Power Producers’ Travis Stewart said the change is significant and interconnection customers have concerns.

National Grid Renewables’ Maggie Kristian said some generation developers weren’t comfortable with load’s small share in the allocation to begin with. She said it’s disappointing to see even that small amount reduced to nothing.

Witmeier said the 100% cost allocation to projects will apply only to the first JTIQ portfolio. He said MISO and SPP will have to “go back to the drawing board” for future JTIQ portfolios and devise a new cost allocation. The RTOs hope FERC gives its blessing for JTIQ planning to become a cyclical process and replace their affected system study process.

Witmeier also said there are always lingering concerns about free riders in transmission cost allocation. He said while interconnection customers might be upset to completely cover the JTIQ bill, load is probably unhappy taking on 100% of MISO’s long-range transmission plan costs.

“We’ve been having this discussion in the MISO community for the past 15-20 years, what is the appropriate formula for generation and load,” Witmeier said.

He said while MISO will hear written concerns on the allocation change through Dec. 6, it’s unlikely to influence changes to MISO and SPP’s direction.

The RTOs also found a change in adjusted production cost benefits of the JTIQ portfolio between MISO and SPP since it first conducted a benefits analysis in 2021. Now MISO can expect to see a $76.5 million benefit, while SPP will experience $99.3 million in benefits over 20 years. The RTOs originally found a $55.7 benefit for MISO and a $132.9 benefit for SPP over the first 10 years the projects are in service.

As far as how the DOE grant will be split between MISO and SPP, that’s unknown, Witmeier said. He said that depends on how many projects apiece from the MISO or SPP clear their respective interconnection queues.

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ERCOT Cancels RFP for Additional Winter Capacity

ERCOT canceled its effort to procure additional generation capacity this winter Nov. 17, citing “limited response” from the market. 

The Texas grid operator was seeking 3,000 MW of capacity with its request for proposal. Participants responded with 11.1 MW of “potentially eligible” capacity. 

ERCOT CEO Pablo Vegas said Nov. 17 during an interview that it was “disappointing that there wasn’t more available.” 

“One of the important outcomes of this RFP process was learning what the market response would be to this type of capacity request,” he said in a statement. “We’ll take these lessons and continue to work with the [Public Utility Commission of Texas] and the market to evaluate other types of demand response products that could contribute meaningfully to electric reliability in the future.” 

The ISO announced its intention in October to increase operating reserves this winter. It listed 20 mothballed and seasonally mothballed dispatchable resources that were eligible to respond to the RFP. Austin Energy and CPS Energy, owners of three of the four largest plants on the list, have said they would not bring their decommissioned units back to life. (See ERCOT Searching for 3 GW of Winter Capacity.) 

Talen Energy notified ERCOT in August that it was planning to indefinitely suspend operations at the other large plant on the list, its 292-MW gas unit outside Corpus Christi. The grid operator evaluated offering a reliability-must-run contract for Barney Davis before Talen withdrew the suspension request on Oct. 27. (See “ERCOT Evaluating RMR Options,” Texas Public Utility Commission Briefs: Aug. 24, 2023.) 

Vegas said no generators offered their decommissioned units in response to the RFP, which presented three-month contracts that were to begin Dec. 1. The program’s 11.1 MW came from entities offering to shed load during emergency conditions. 

The awards would have been announced Thursday. 

The ISO said it weighed factors such as the program’s costs and the incremental additional complexity for its control room against the very small amount of capacity and the minimal reliability benefits in declining to proceed with the RFP. 

“It will come as a surprise to no one that knows anything about power markets that ERCOT’s Hail Mary attempt to procure zombie power plants failed,” Stoic Energy CEO Doug Lewin said on X, formerly known as Twitter, putting in a plug for energy efficiency’s benefits. 

The RFP also drew pushback from the PUC’s commissioners, who expressed concerns during an open meeting earlier this month over ERCOT’s refusal to place a firm cap on the program’s costs. Vegas told the commission staff had not yet set a budget for the RFP. 

Commissioner Will McAdams said the RFP should be considered an interim or bridge solution under state rules. That would mean it would compete with funds under the $1 billion cap designated for the performance credit mechanism. 

ERCOT said it “firmly believes” expanding demand response capabilities in the industrial, commercial and residential customer classes offers “tremendous potential.” It said it will work with the PUC and stakeholders to explore incentives and product designs that may work better in the future. 

The RFP was based on probabilistic analysis indicating ERCOT faced a 20% risk of entering energy emergency alert conditions this winter if the system was hit with another event similar to last December’s Winter Storm Elliott. It said the 3,000 MW of additional capacity that could be called upon if needed was an “added layer of protection” during peak demand. 

“The [RFP] was an extra layer of precaution to mitigate higher risk during extreme weather this winter,” Vegas said. “ERCOT is not projecting emergency conditions this winter and expects to have adequate resources to meet demand.” 

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MISO Decides Battery Storage Can Use As-available Tx Service

CARMEL, Ind. — Battery storage that charges from the grid should be able to use non-firm transmission service, MISO has decided.   

MISO is discarding its previous requirement that battery storage needs to secure yearly, firm point-to-point transmission service before it can charge from the grid.  (See MISO Agrees to Dial Back Tx Service Requirements for Energy Storage.)  

Manager of Resource Utilization Kyle Trotter debuted draft business practice manual language adopting the changes at a Nov. 15 Planning Advisory Committee meeting.  

Staff in October said battery storage should be treated like any other intermittent load in MISO and should be able to use as-available transmission service. That means storage owners will be free to use the less expensive non-firm, point-to-point transmission service or MISO’s Network Integrated Transmission Service for any length of time.   

Trotter said MISO hopefully will be able to incorporate the change formally by the first quarter of 2024. He said if the Planning Advisory Committee is receptive, MISO will test out the changes with the Market Subcommittee in January.  

Changes to MISO’s business practice manuals require only a review from MISO’s legal team to be implemented. They are not filed with FERC.  

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NERC ‘Very Happy’ With GridEx VII Participation

NERC’s GridEx security exercise may be in its seventh iteration, but it still packs a challenge for participants across the electric grid, stakeholders said in a Nov. 16 media call.

According to Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), more than 250 organizations took part in the distributed play portion of GridEx VII, held Nov. 13-14. The distributed play was followed by an executive tabletop session Nov. 16, in which executives from the electricity, natural gas, telecommunications and finance sectors participated, as did representatives from the U.S. and Canadian governments and the Electricity Subsector Coordinating Council.

The participation rate was “pretty consistent with … prior GridExes,” Cancel said.

GridEx VI, held two years ago, saw participation from 293 organizations, the lowest number since the second exercise in 2013. (See NERC: GridEx Lessons Already In Use.) Nonetheless, Cancel said the E-ISAC, which developed the core exercise scenario for the distributed play as well as the virtual environment for the exercise, was “very happy with the level of participation,” particularly the involvement of other critical infrastructure sectors in the planning, distributed play and executive tabletop.

Electrical equipment vendors also played a part in this year’s exercise, as they have in previous years. Participants said the sector’s representation mostly came from original equipment manufacturers, who provided input into issues such as supply chain shortages that are causing growing concern.

“We do include vendors … not only in the actual drill, but even in the planning for the drill and coming up with scenarios, and that’s been valuable,” Cancel said. “They face the same threats that we face, they have insights, and they can provide value, so we’re looking forward to continuing to leverage that as we go forward.”

Cyber and Physical Attacks Simulated

Other real-world issues continued to influence this year’s distributed play and executive tabletop scenarios, stakeholders said. While details about the distributed play scenario — which participating organizations customized to fit their needs after the E-ISAC gave them the general themes — have not been released, participants in the call mentioned cyber intrusions by nation-state actors attacking the grid either directly or through supply chains, or spreading misinformation on social media.

Physical violence, another increasingly prominent focus of security specialists, also constituted “a substantial portion of the drill,” Cancel said. Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), said exercises like GridEx provide an opportunity for utilities and law enforcement to practice not only bringing those responsible to justice, but also preventing as much harm as possible.

“When people commit these types of crimes, it’s … a very unsafe environment. It’s not just unsafe for the general public, if the power goes out and critical resources aren’t available; it’s actually unsafe for the individuals committing these crimes as well,” Kumar said. “So getting that awareness of how unsafe trying to commit a crime like this actually is” remains a major focus for DOE and CESER.

Pandemic’s Lessons Resonate

Participants also noted the continuing legacy of the COVID-19 pandemic, despite the absence of travel restrictions that limited the GridEx VI executive tabletop to remote attendance only.

Duane Highley, CEO of Colorado-based Tri-State Generation and Transmission Association and co-chair of the ESCC, noted that his organization’s version of the distributed play included simulating the loss of its headquarters. Because “the ability to work remotely has really been enhanced” during the pandemic, Highley said reconnecting the company’s employees was much simpler than it would have been in previous years.

Kevin Wailes, CEO of Lincoln Electric System in Nebraska and ESCC co-chair, added that “the virtual environment provides the opportunity for a lot more participation [by small utilities and co-ops] than we’ve … had in the past.” Pedro Pizarro, another ESCC co-chair and CEO of Edison International, said he was glad the scenario included simulation of the loss of communications, because the experience of the pandemic made it “critical that we prepare for that kind of scenario.”

Cancel emphasized that the landscape of threats facing the energy sector is dynamic and evolving and that while events like GridEx can help entities practice their response to recently identified risks, there are always more dangers emerging. Kumar said one benefit of GridEx is its ability to bring together stakeholders both inside and outside the industry to practice their communication skills so they can engage quickly when malicious actors try to exploit new vulnerabilities.

“The reality is that there’s always going to be vulnerabilities; we just need to figure them out before someone else does and takes advantage of them,” Kumar said. “Exercises like this really bring the manufacturers closer together with the energy sector community, both in industry and government, to really start to mature what I like to think of as [operational technology] vulnerability disclosure. … I think that’s a very positive sign in terms of where we’re headed with vulnerabilities.”

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DOE Proposes Expanding NEPA Exclusions for Clean Energy, Transmission

The U.S. Department of Energy Thursday proposed revisions to its regulations under the National Environmental Policy Act that would expand the scope of “categorical exclusions” for transmission and clean energy. 

The exclusions would apply to projects that are shown to not have a significant environmental effect. It would create a new exclusion for energy storage projects within previously disturbed or developed areas, while changing exclusions for solar energy and transmission. 

DOE reasoned that upgrading lines can prevent the construction of new ones, with the Notice of Proposed Rulemaking (NOPR) highlighting reconductoring as a means of capacity expansion, which can increase the amount of renewable energy on the grid. 

“Improvements to capacity and efficiency can help to ensure reliability, reduce costs to consumers and reduce [greenhouse gas] emissions associated with electricity generation, transmission and distribution,” said the notice in the Federal Register. 

Rebuilding transmission lines is currently exempted, but only up to 20 miles. The proposal would remove that mile limit. The department reasoned that the environmental impact of a line is not related to its length. 

It also would expand the exclusion for relocating segments of a line to existing rights of way or previously disturbed or developed lands. Regulations currently include language limiting relocation exemptions to “minor” relocations of small segments; the proposal would remove the word “minor.” 

The storage exemption applies to electrochemical batteries and flywheels within previously disturbed or developed areas, or within small sites near such areas.  

The current categorical exclusion for solar is limited to projects of 10 acres or below, but DOE said acreage is not a reliable indicator of environmental impact and would remove that limit in the proposal. Projects larger than 1,000 acres on previously disturbed or developed land have not had significant environmental impacts, it said. 

DOE expects that the new exclusions will save it money and time, while improving the reliability and resilience of the electric grid. Expanded electricity generation that helps to reduce greenhouse gas emissions is another benefit. 

The department is taking comments on the proposal through Jan. 2. 

Speaking after FERC’s open meeting Thursday, Chair Willie Phillips said that the proposal would have more impact on DOE’s transmission siting authority. The commission has its own pending NOPR implementing its backstop siting authority granted by the Infrastructure Investment and Jobs Act. (See FERC Backstop Siting Authority Runs into Opposition from States.) 

DOE’s proposal was welcomed by American Council on Renewable Energy President Gregory Wetstone in a statement. 

“A dramatic increase in renewable energy and transmission infrastructure is needed to enhance reliability, lower energy costs and maximize the benefits of the Inflation Reduction Act,” Wetstone said. “A key barrier is the often lengthy siting and permitting process. ACORE supports the use of categorical exclusions for projects that will produce a cleaner grid and not adversely impact the environment. This mechanism improves siting and permitting while maintaining NEPA’s core environmental provisions.” 

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Popular Incentive Dropped from CARB’s $624M EV Funding Package

California regulators approved a $624 million clean transportation incentive funding package on Thursday but said goodbye to a flagship program that helped consumers in the state buy more than 500,000 zero-emission or hybrid light-duty vehicles. 

The California Air Resources Board (CARB) approved a funding plan for 2023/24 that includes $455 million in incentives for zero-emission drayage trucks and school buses.  

Another $28 million will go to the Clean Cars 4 All program, which pays lower-income consumers to scrap their old cars and buy a cleaner vehicle. An e-bike incentive program will receive $18 million, and $14 million will go to the Clean Off-Road Equipment incentive program. 

But the plan does not include money for the Clean Vehicle Rebate Project (CVRP), which has received $1.61 billion since its launch in 2010 and provided incentives for the purchase of about 533,000 vehicles. 

CVRP ran out of money and closed to new applications effective Nov. 8. The program offered incentives of up to $7,500 for the purchase of new battery-electric, plug-in hybrid and fuel cell vehicles. The program included income caps, but they were less restrictive than those of Clean Cars 4 All. 

Stephanie Parent with CARB’s Mobile Source Control Division said CVRP had been “a huge success story.” 

“CVRP achieved its goal of accelerating the deployment of ZEVs in California and provided highly useful ZEV market information to stakeholders in California and beyond,” Parent told the CARB board on Thursday. 

According to the California Energy Commission’s ZEV dashboard, 1.7 million light-duty ZEVs have been sold in California. So far this year, ZEVs accounted for 25% of new car sales. 

Rather than providing purchase incentives for the broader ZEV market, CARB will now shift its focus to lower-income consumers through its Clean Cars 4 All and finance assistance programs. 

Smaller Package

The $624 million incentive package that CARB approved on Thursday is substantially smaller than the $2.6 billion approved last year for 2022/23. That was the agency’s largest budget yet for the incentives. (See CARB Approves $2.6B in Clean Vehicle Incentives.) 

The current package includes $455 million in incentives for zero-emission heavy-duty vehicles: $80 million for drayage trucks and $375 million for public school buses. Those incentives will be available through the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). 

The drayage truck incentives will help fleets meet the requirements of CARB’s Advanced Clean Fleets (ACF) regulation adopted in April. Under ACF, all new trucks added to drayage fleets must be zero-emission starting in 2024, and all drayage trucks must be ZEVs by 2035. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.) 

The state budget didn’t give CARB funding for other types of heavy-duty vehicles that are eligible for HVIP incentives. But HVIP received $1.8 billion in the 2022/23 funding plan, and the program reports that incentives are still available. 

On the light-duty side, the $28 million going to Clean Cars 4 All will be split into two parts. Half will go to air districts that have been administering the program since its launch. The other half will go to a new statewide expansion of the program. 

CARB’s incentive funding plan also includes the addition of zero-emission motorcycles (ZEMs) as an eligible vehicle in Clean Cars 4 All. Incentives for ZEMs were previously only available through CVRP. 

The Tesla Effect

CVRP received a $515 million allocation for 2021/22 that was intended to fund the project through June 2024. But earlier this year, CARB estimated the project would run out of money as soon as October of this year. 

That’s because Tesla in February reduced the price of two of its models — Model 3 and Model Y — making them again eligible for the CVRP incentive after losing eligibility in 2022. Starting in March, CVRP applications surged to about 12,000 per month. (See California EV Rebate Program Expected to Run Empty Ahead of Plan.) 

Following the board’s approval of the incentive funding package on Thursday, CARB Executive Officer Steven Cliff read a resolution expressing appreciation to the Center for Sustainable Energy, which ran the CVRP program for nearly 14 years.