Ransomware continues to pose a serious problem for critical infrastructure and industrial organizations despite a slight drop in the number of incidents in the second quarter of 2022, according to a report from cybersecurity firm Dragos released on Tuesday.
Dragos bases its quarterly ransomware assessments on information from “publicly disclosed incidents, network telemetry and Dark Web posting.” The most recent report identified 125 distinct ransomware incidents in the second quarter, down from 158 in the first quarter; 23 of the 37 ransomware groups targeting industry and infrastructure that Dragos monitors were active, as opposed to 22 in the previous period.
This latest report focuses in part on the churn witnessed in the ransomware ecosystem, most notably the apparent shutdown of the Conti cybercrime gang in May after its attack on the government of Costa Rica drew the attention of the U.S. State Department. According to reports from cyber intelligence companies, the gang gained a foothold in a computer system of Costa Rica’s Finance Ministry, subsequently spreading to multiple government agencies and leading officials to declare a state of emergency.
Conti announced it was shutting down operations in May and took all its websites offline the following month. Dragos attributed the drop in cyber incidents primarily to this shutdown but said it is highly likely that the group has not gone away for good. Instead, experts believe the gang has split into smaller subgroups that joined or started new criminal operations with other cybercrime veterans.
One example is the group Black Basta, which claimed responsibility for an attack against agriculture equipment manufacturer and distributor AGCO in May. Dragos said researchers suspect that Black Basta, which it called “significant [and] threatening,” is being managed by former members of Conti and REvil, a notorious gang responsible for last year’s attack on global meat company JBS and itself suspected of being an offshoot of the DarkSide hacking group that attacked Colonial Pipeline. (See Glick Calls for Pipeline Cyber Standards After Colonial Attack.)
Most of the global ransomware targets last quarter were in Europe; Dragos recorded 46 attacks, or 37% of the total, in the continent. North America came next, with 36 attacks — 29% of the total, down from 42% in the first quarter — followed by Asia with 32. South America, the Middle East and Africa were apparently much less enticing targets, with six, four and one attack, respectively.
Eighty-six of the attacks in the second quarter were directed against the manufacturing sector; automotive companies bore the brunt with seven attacks. The energy sector tied for second with food and beverage companies, at 10 attacks each.
Dragos said that the second quarter’s attacks, though less numerous, were “more impactful,” noting an attack on factories operated by Foxconn in Mexico that caused the facilities to be shut down for several weeks. Operational technology networks continue to be a major target, and the firm warned that even attacks that only manage to penetrate a company’s information technology can still “negatively impact OT operations” if the networks interact.
Dragos predicted that fresh ransomware groups will continue to pop up in the third quarter, either made up of veterans or newcomers to the cybercrime world. In light of “continuous political tension between Russia and Western countries,” the firm said it could forecast continued targeting of OT operations with “moderate confidence.”
The Inflation Reduction Act (IRA) has “a lot of positive elements” that would support the natural gas industry’s efforts to provide decarbonization solutions for reaching net-zero emissions by 2050, Rick Murphy, managing director at the American Gas Association, said Tuesday.
“We have been hard at work digging through this 800-page or so piece of legislation … and we do think that [it] is better than most other proposed legislation that has surfaced over the last year,” Murphy said during an E-Dialogues webinar on natural gas in a net-zero future.
Senate Majority Leader Chuck Schumer (D-N.Y.) and Sen. Joe Manchin (D-W.Va.) reached a deal July 27 on a climate package for the IRA, which passed the U.S. Senate on Sunday. (See Senate Passes Inflation Reduction Act.) Speaker Nancy Pelosi (D-Calif.) has promised that the U.S. House of Representatives will pass the legislation without changes.
There are measures in the IRA that Murphy said align with the AGA’s Net-Zero Emissions Opportunities for Gas Utilities report released in February. He lauded opportunities in the legislation to advance renewable natural gas and hydrogen through tax credits as “very positive.”
“There are incentives for combined heat and power, particularly if [CHP] is then matched up with renewable sources of natural gas,” he said.
The legislation represents a “watershed moment” for understanding the role of a diverse set of renewables for the U.S. energy grid, said Mary Moerlins, director of environmental policy and corporate responsibility at NW Natural (NYSE:NWN). “This is the first time that we’ve seen, at a federal level, the recognition of the importance of renewable gases and the development of them to decarbonize the pipeline delivery system.”
The IRA also represents the first federal legislation that references gas heat pumps (GHP), according to Murphy. Residential GHPs and GHP water heater purchases would be eligible for a tax credit.
GHP technology is not available for residential use in the U.S. yet, but some utilities are pushing for their introduction to the market “late next year, or early the following year,” Jerome Ryan, director of SaveGreen at New Jersey Natural Gas (NYSE:NJR), said during the webinar.
NJ Natural Gas is one of 14 organizations that founded the North American Gas Heat Pump Collaborative. “We formed that collaborative to try to introduce market transformation for GHPs so that they can come to market and start to help us on this decarbonization journey,” Ryan said.
The technology uses natural gas instead of electricity for the compression functions of a heat pump and can use water as a refrigerant instead of less environmentally friendly refrigerants often used in electric-based heat pumps.
“We see a huge leap forward in efficiency with the introduction of gas heat pumps,” Ryan said.
Carl Garofalo, director of sustainability solutions at Southern Company Gas (NYSE:SO), highlighted the bill’s weatherization rebates as an opportunity to address the energy efficiency of “entire homes, especially for low-income customers.”
He said those rebates will allow homeowners to combine end-use energy efficiency upgrades for furnaces or water heaters with whole-building envelope improvements.
“If you address the entire building and improve your insulation, doors and windows and then put that better equipment into it, it’s really going to move the needle,” he said. “We look forward to leveraging the dollars that are in that portion” of the bill.
Murphy called energy efficiency programs that are administered by U.S. gas utilities the “cornerstone” of any decarbonization strategy.
“Over the last 40 years, the number of residential gas customers has grown by 71%, and during that time, overall, the demand has remained relatively flat,” he said. “These efficiency programs have been extremely beneficial in helping to address the energy demand across not only the residential sector, but all the other sectors that [gas utilities] serve.”
Ohio-based Lordstown Motors (NASDAQ:RIDE) said it will begin manufacturing its light-duty electric truck model, the Endurance, in the next six to eight weeks, with deliveries to commercial customers in the fourth quarter. Sales to the public are expected later.
The company affirmed the start-of-production target during its second-quarter earnings call Aug. 4. It had announced last November that it would push back production to the third quarter of this year, citing supply chain problems.
Last week’s announcement was just the latest twist in a long road to manufacturing and profitability for the startup, putting the company in the lead of a small parade of entrepreneurial groups struggling to engineer and manufacture novel electric vehicle models, while the behemoth, “legacy” carmakers prepare to mass produce their own models.
General Motors (NYSE:GM), for example, announced in June that it was slashing the sticker price of its Chevy Bolt by $6,000 to a starting price of $25,600. That price cut, which made the Bolt the least costly EV, came before the latest effort by Congress to pass legislation addressing climate change.
Chevy Bolt | Chevrolet
The Inflation Reduction Act, approved by the Senate on Sunday and in line for approval by the House of Representatives this week, would renew the current $7,500 tax credit for the purchase of a new EV but without the limit on the number of vehicles sold. It would also be available at the point of sale rather than in the consumer’s next tax filing.
The credit runs through the end of 2032. The legislation would require that the vehicle be made in the U.S. and that materials in the battery must come from the U.S. or countries with which the U.S. has free-trade agreements. But those provisions would not fully kick-in until 2024.
In addition to announcing that production is on-track, Lordstown last week reported an operating profit of $61.2 million, largely because the company completed the sale of its 6.2 million square-foot production facility, a former GM assembly plant, to Foxconn for $230 million. The company is still looking for more capital.
The sale of the plant is at the center of a joint venture with Foxconn, making Lordstown the Taiwanese company’s “primary development partner in North America,” according to Lordstown.
“I am excited by my expanded role as CEO of Lordstown and the joint venture with Foxconn,” said Edward Hightower, who took over leadership of the company July 12. “In Q2, we made significant progress towards our plan to launch the Endurance in Q3 of 2022 and begin sales in Q4.
“We look forward to getting the Endurance into customers’ hands, as we think they are going to love it. We have also started pre-development work on the first vehicle under our joint venture. Our team is excited to create and launch future products while leveraging the Foxconn EV ecosystem.”
Fisker
A future competitor to Lordstown, Fisker (NYSE:FSR) also reported second-quarter results last week. The company announced it has contracted with Foxconn to build an electric SUV it will call the PEAR at the former Lordstown plant beginning in 2024. The price will begin at just below $30,000. The company expects the car to qualify for the federal tax credit.
The company plans to build a minimum of 250,000 Pears and has already received 4,000 requests for reservations.
Fisker Ocean | Fisker
Fisker has also logged 5,000 reservations for its first vehicle, the Ocean, a larger, luxury SUV that is also not yet in production. The company said it expects to begin producing the car with a contract manufacturer in November at a plant in Europe. Consumers paid a $5,000, nonrefundable deposit to make the reservations.
CEO Henrik Fisker, a Danish-American auto designer based in Los Angeles, said the company has built 55 prototypes of the Ocean and that crash tests of some of the vehicles indicate it will achieve a five-star rating, the highest possible, next year when the National Highway Traffic Safety Administration conducts its own tests.
Mr. Fisker added that he had driven the car on a high-speed track in Italy, as well as on city streets in Los Angeles.
“I can promise anybody this is going to be one of the best handling SUVs in the world, hands down, specifically when you combine the actual cornering and driving ability and performance compared with comfort,” he said. “It’s easy to make a super sporty car, and it’s easy to make a super comfortable car, but combining the two for everyday use is super difficult, and we have really achieved this.”
Canoo Motors
Canoo Motors (NASDAQ:GOEV), based in Justin, Texas, which defines itself as a technology company first and carmaker second, reported its second-quarter results Monday afternoon, revealing it has already logged more than 10,000 orders.
Canoo Pickup Truck | Canoo
The company is targeting commercial as well as individual consumers with a “lifestyle vehicle” available in 2023. The company has already built 89 prototype vehicles, some of which have already been used as commercial delivery vehicles, while others have been used in crash testing.
During the analyst call, Ramesh Murthy, chief accounting officer, said Walmart has ordered 5,000 vehicles from the company for use as delivery vehicles. The contract includes an option to buy 10,000 more.
NASA has also awarded Canoo a contract to build an EV for the Artemis program to return humans to the Moon in 2025, and the U.S. Army has selected the company’s EVs for testing in its program to electrify its vehicle fleet.
Canoo reported it spent $115.5 million during the quarter on research and development, Murthy told analysts.
“We have customers; we have access to capital. We have a strategy that benefits our company and shareholders against the backdrop of this global economic condition. We are making it happen,” he said.
Executive Chairman and CEO Tony Aquila said all versions of the vehicle will be built on the same platform, which has only 1,800 parts currently and will have 1,600 parts when commercial production begins.
“Over the past five quarters, we have worked to guide the market to understand our different approach and that we are a technology-first-centric advanced mobility company, and that we understand true total cost of ownership because we come from the service maintenance repair technology side of the industry.”
The company appears to have a “Made in America” focus.
“During the quarter we saw many legacy OEMs struggling with quantity … and their reliance on Chinese-made parts and technologies. … The majority of our focus to date has been on technology and real product validation. Our decision to prioritize domestic manufacturing at the end of last year was the right move.”
New Jersey could encourage greater use of electric vehicles in overburdened communities by creating larger purchase incentives, targeted incentives for used vehicles and EV-based ride-sharing plans, according to a draft report by the state’s Board of Public Utilities (BPU).
The challenges include EVs’ high price tag, the difficulty of owning any type of vehicle in those communities due to parking and other limitations, and the obstacles to installing chargers that serve multi-unit dwelling units (MUDs), which house about 36% of New Jersey’s population and are especially prevalent in low-income areas.
The report suggests counteracting those obstacles by ensuring a greater density of direct current fast chargers in overburdened communities, which would require more consistent funding of incentives to install chargers around MUDs. EV uptake also could be stimulated through incentives encouraging ride-share drivers to install Level 2 chargers in their homes and providing them with an “advantageous rate” for electricity.
The report’s perspective aligns with a similar assessment released in June by the Information Technology Innovation Foundation, which concluded that a broader uptake of EVs, especially in low-income and minority communities, will be needed if the U.S. is going to reach its ambitious clean energy transportation goals.
“Conventional approaches that encourage adoption of this early stage technology are primarily reaching a distinct group of higher-income individuals,” said the foundation’s report, “Clean and Just: Electric Vehicle Innovation to Accelerate More Equitable Early Adoption.”
EVs accounted for about 4% of U.S. vehicle purchases in 2021, the report says, and “research shows that early adopters tend to be higher-income, well-educated, and predisposed to environmentally friendly technologies.”
But a much broader driving demographic will be needed to reach the target of having EVs account for 60% of new car sales by 2030, and that will require new motivational strategies, the report said.
Electric vehicles made up 4% of new vehicle sales in the U.S. in 2021. | Information Technology and Innovation Foundation
“Conventional approaches to encourage the purchase of EVs may fail to reach low-income and disadvantaged communities,” the report said. “Because these groups face distinct challenges in adopting the technology.”
In contrast, by “intentionally including a diverse range of users early in the adoption process, technology providers can more effectively identify issues and modify the technology to successfully appeal to a mass market,” the report concludes.
New Jersey officials have already recognized that dynamic on a small scale. The BPU, for example, changed the incentive strategy in its Charge Up New Jersey program after 83% of incentives in the first phase went to purchasers of Tesla vehicles, which are among the most expensive EVs.
The agency in the second phase allowed purchasers to get the maximum incentive — at the time $5,000 and now reduced to $4,000 — only if they bought a vehicle with a price tag of no more than $45,000, which allowed for only the lowest-priced Tesla model. (See NJ EV Incentives Target Cheaper Vehicles, Middle-income Buyers.)
Lawmakers also recognized the need to put EVs in urban areas in a bill signed Thursday by New Jersey Gov. Phil Murphy. The law allocates $45 million to a three-year pilot program that will test electric school buses and related charging stations in 18 school districts around the state.
Half the funding will go to EV buses for low-income, urban or environmental justice communities in order to mitigate the disproportionate health impacts of medium- and heavy-duty vehicles on vulnerable populations. (See Electric School Bus Pilot Awaits NJ Governor’s Signature.)
Priorities in Cutting Emissions
Maria Lopez Nunez, deputy director of organizing and advocacy for the Ironbound Community Corporation, is skeptical that focusing on introducing EVs is an effective way to reduce emissions in disadvantaged communities, especially given the obstacles to EV ownership in those areas.
Such a strategy is simply putting a “Band-Aid” on the problem, said Lopez Nunez, who lives in Newark, one of the state’s most disadvantaged communities and one of those analyzed in the report. She said she is not sure if she was consulted by the report’s researchers, but she has expressed her views to state officials several times on the kind of issues it raises.
“It’s treating a symptom, not the root cause here,” she said. “When we’re talking about personal vehicles, you know, you’re talking about something that’s really inaccessible for communities like mine, where up to 40% of people don’t have a car. So, they’re not going to get a car now that it’s electric. That’s out of reach for most folks.”
The key polluters in the community are heavy-duty trucks and fossil fuel plants, she said. So, electrifying heavy trucks and shutting down the plants would have a much greater impact, she said.
“This is meant to help middle-class New Jersey, who want to transition [to EVs] and that’s OK,” she said, of the proposals outlined in the BPU’s report. “But let’s not pretend that it’s helping overburden communities.”
Locating Charger Sites
The BPU compiled the report with funds from the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy. Although the work was conducted by its own staff, the BPU says that it has not yet taken a position on the plans outlined in the report.
New Jersey defines overburdened communities as any census block in which at least 35% of the households qualify as low-income; at least 40% of residents are minorities; or at least 40% of households have limited English proficiency. They account for about 4.7 million people, or slightly more than half the population of the state.
To compile the report, researchers reached out to three overburdened communities in the state — Newark, New Brunswick and Washington Township — and talked to local government representatives, community group leaders, and industry experts. The researchers paid particular attention to cities in which EV infrastructure is insufficient to enable drivers to own an EV with the “same level of ease” as people who can charge it at their own residence. The report also focused on “transportation deserts,” where access to public transportation is limited, and areas with multi-unit dwellings.
Those communities find it especially difficult to adopt EVs due to the high upfront cost and lack of used EVs for sale, the report said. Disadvantaged residents also may lack access to financial tools, such as checking accounts or credit cards, smartphones or the internet, which are needed to connect to charging networks or to identify available charging services.
The existing lack of available parking also weighs heavily on efforts to get EVs into those communities, according to the report. It quoted a Newark government official saying the city was particularly hampered in introducing EVs because the city “does not have enough public lots in high traffic areas to build out sufficient EV charging infrastructure.”
That puts the emphasis on making sure that multi-dwelling units have parking and charging infrastructure, the report said. The report suggested that the problem could be remedied by developing “neighborhood charging lots,” where residents could charge overnight and “start their day with a full charge.”
The lack of parking and obstacles to personal vehicle ownership underscore the importance of ride-hailing services, the report said. Such services can negate the need for personal vehicles in cities and can be more economic for users because the relatively short trip lengths mean the ride is not too expensive, the report said.
EV Promoting Private Initiatives
The Information Technology Innovation Foundation report concludes that “innovation is a key strategy to both addressing disparities in EV adoption and aiding the broader goal of mass adoption.”
Madeline Yozwiak, a doctoral student at Indiana University Bloomington and one of the authors of the report, said one difficulty to be overcome before overburdened communities can embrace EVs is to adjust the federal incentive system. The main federal incentive available at present is a $7,500 tax credit, but many people in those communities don’t earn enough to pay that amount of taxes, and so can’t take all of the credit, she said during a July 26 webinar on the report.
She said that range anxiety, an issue in all communities, can be heightened in low-income communities.
“For example, if you’re traveling longer if you live further from where you work due to the cost of housing closer to your place of employment,” she said. “Or if you’re an individual in a rural community where your average trip tends to be longer than someone who lives in a denser region of the country.”
Yozwiak and the report identified several innovators that are seeking to address some of the obstacles, including:
SparkCharge, a company that offers a subscription service in which the company will bring mobile battery chargers to charge the subscriber’s car.
Recurrent Energy, which, according to the report, “uses data monitoring of existing EVs to create used-EV purchase reports, which can decrease purchase barriers for affordable, used vehicles.”
Sway Mobility, which develops “micro” car-sharing programs, as small as one vehicle, for partner organizations working in marginalized communities. That can decrease the cost of creating a car-sharing program, the report says.
Two Washington agencies last week said they reached a “major milestone” in nailing down new rules to implement the state’s 2019 Clean Energy Transformation Act (CETA).
Adopted mostly along party lines in the Democrat-controlled legislature, CETA requires all electric utilities in the state to become greenhouse gas-neutral by 2030 (allowing for use of offsets and other programs) on the way to generating all power from emissions-free resources by 2045. It also prohibits utilities from serving their Washington customers with any coal-fired generation after 2025.
The law sets a $100/MWh penalty for each violation that occurs after the legal deadlines. It also includes a penalty multiplier of 1.5 for violations that include coal-fired generation and a multiplier of 0.84 for gas-fired combustion turbine generation. Combined cycle generation would be subject to a 0.60 multiplier.
Washington has only one coal-fired plant, TransAlta’s Centralia facility, which is scheduled to shut down in 2025.
In the most recent round of CETA rulemaking, Washington’s Utilities and Transportation Commission (UTC) and Department of Commerce clarified that utilities may use energy storage systems, such as batteries or pumped hydro plants, to manage their renewable energy supplies.
The new regulations say renewable electricity can be stored in batteries or other facilities in Washington or elsewhere and be used later without losing its “renewable” label, Glenn Blackmon, manager of energy policy for the Department of Commerce, told NetZero Insider.
Another new rule prevents double-counting of the renewable energy that utilities use to meet Washington’s clean energy standard and prohibits other companies that buy and sell energy from counting the same clean energy toward requirements in other states.
“These rules are an important step toward ensuring that electric utilities are working actively toward a clean, reliable and sustainable energy future for Washington,” UTC Chair David Danner said in a statement. “The work isn’t over, but I am confident that by working with our utilities, state government partners and the public we are well on our way to 100% carbon-free electricity by 2045.”
Last week’s developments mark the second round of rulemaking for CETA. A third round is not scheduled, but cannot be ruled out, Blackmon, said.
The UTC’s rules apply to Washington’s three investor-owned utilities: Avista, PacfiCorp and Puget Sound Energy. The Commerce Department’s rules cover roughly 60 consumer-owned utilities, which include municipal utilities, public utility districts and rural electric cooperatives.
Following a marathon overnight session of debate and amendments, the U.S. Senate on Sunday passed the Inflation Reduction Act with all of its $369.75 billion in clean energy spending intact.
Under special budget reconciliation rules that allowed passage with a simple majority, the bill was approved on a 50-50 party-line vote with Vice President Kamala Harris providing the tie-breaking vote that will now send the bill to the House of Representatives.
Speaking before the vote, Senate Majority Leader Chuck Schumer (D-N.Y.) called the bill “one of the defining legislative feats of the 21st century” and “the boldest climate package in U.S. history. This bill will kickstart the era of affordable clean energy in America. It’s a game changer.”
“Senate Democrats sided with American families over special interests,” President Biden said in his statement hailing the IRA vote. “This bill … makes the largest investment ever in combating the existential crisis of climate change.”
House Speaker Nancy Pelosi (D-Calif.) promised “the House will return and move swiftly to send this bill to the president’s desk.”
Getting to the Sunday afternoon vote has taken close to a year, beginning with Democrats’ $2.2 trillion Build Back Better Act originally introduced in September 2021. Sen. Joe Manchin (D-W.Va.) walked away from negotiations on trimming the bill’s price tag twice, once in December and again earlier in July.
But Schumer and Manchin hammered out the renamed IRA, with tax reform, health care and clean energy measures, behind closed doors last month, framing it as an inflation fighter that would reduce health care and energy costs for American families and cut the federal deficit by more than $300 billion. (See Schumer, Manchin Reach Climate Deal.)
In a Twitter thread following the vote, Manchin praised passage of the bill as the result of years of cross-aisle efforts to “determine the most effective way to increase domestic energy production, lower energy and health care costs, and pay down our national debt without raising costs for working Americans.”
Still, with a 50-50 split in the Senate, Schumer and Manchin had to negotiate further concessions to ensure the critical vote of Sen. Krysten Sinema (D-Ariz.). Sinema was successful in removing language from the bill that would have closed a tax loophole on the profits of high-income hedge fund investors and asset managers.
Republicans also forced two last-minute changes to the bill during the 13-hour “vote-a-rama,” that began late Saturday night and ended just after 3 p.m. Sunday. Part of the budget reconciliation process, the rules allow an unlimited number of amendments to be considered before a final vote on the bill.
The amendments offered by GOP senators during this time were often unrelated to the bill and were mostly voted down. However, the Republicans were able to remove a $35/month cap on insulin payments for consumers with private insurance, while retaining the cap for consumers on Medicare.
They also pushed through a further change on the bill’s 15% corporate minimum income tax, exempting companies owned by private equity from the provision.
‘An Arsenal of Clean Energy’
However, Republican attempts to change the bill’s energy provisions were universally voted down.
For example, Sen. John Barrasso (R-Wyo.), ranking member of the Senate Energy and Natural Resources Committee, offered an amendment that would have required the Department of Interior to hold additional sales of onshore oil and gas leases on public land by the end of 2022.
Similarly, an amendment from Sen. John Kennedy (R-La.) would have required the sale of offshore oil and gas leases, while Sen. Richard Shelby (R-Ala.) proposed requiring new coal leases.
“The Democrats’ war on American energy continued today,” Barrasso said in a statement following passage of the IRA. “While jamming through their reckless tax and spending spree, Democrats voted against common-sense Republican proposals.”
Clean energy advocates were quick to applaud the bill’s passage and its clean energy incentives, ranging from various tax credits to incentives for big transmission projects and for consumers purchasing electric vehicles.
“Rising inflation and global instability have put America’s energy security in jeopardy,” said Nat Kreamer, CEO of Advanced Energy Economy. “A federal clean energy investment of this magnitude is our best defense.”
Key clean energy provisions in the bill include extensions of the solar investment tax credit and wind production tax credit, through the end of 2024, to be followed by technology-neutral clean-energy credits that will provide incentives for renewables, nuclear and green hydrogen. (See What’s in the Inflation Reduction Act, Part 1 and What’s in the Inflation Reduction Act, Part 2.)
Tax credits for electric vehicles, both new and used, are also part of the package, with EVs costing less than $55,000 eligible for a $7,500 credit and used EVs costing less than $25,000 getting a $4,000 credit. Incentives for transmission include $2 billion in direct loans for construction and modification of transmission deemed in the national interest and $760 million in grants for permitting and siting and for economic development in communities with transmission builds.
Virginia regulators warily approved a $78.7 million rate hike for Dominion Energy’s 2.6-GW Coastal Virginia Offshore Wind (CVOW) project Friday, warning that the legislature had left ratepayers facing “unprecedented risks” of cost overruns and delays on the massive $21.5 billion project.
With a projected capital cost of $9.8 billion, the project “will likely be the largest capital investment, and single largest project” in the utility’s history, the State Corporation Commission (SCC) said in its 45-page order, which also approved the interconnection and transmission facilities to connect the project to the PJM grid (PUR-2021-00142). “The project will also likely be the costliest project being undertaken by any regulated utility in the United States, with the exception of Southern Co.’s ongoing Vogtle nuclear project, and will likely be the most expensive on a dollars-per-kilowatt of firm capacity basis.”
Total project costs, including financing costs minus investment tax credits, are estimated at $21.5 billion, including a $7.22 billion return on equity based on Dominion’s 9.35% ROE rate.
The new rate adjustment clause (Rider OSW) will cost a residential customer using 1,000 kWh/month an average monthly bill increase of $4.72 over the projected 35-year lifetime of the project, with a peak increase of $14.22 in 2027, the commission said.
Ratepayers at Risk
“While neither staff nor any respondent opposed approval of CVOW, significant concerns were raised throughout this proceeding regarding affordability and the financial risk to ratepayers,” the commission noted. “The project is truly distinctive in numerous respects, encompassing cost, size, technology, complexity, ownership and risk. … No other utility or independent developer has attempted to construct and operate an offshore wind project of this size in the United States.”
Unlike other East Coast states backing offshore wind, Virginia did not choose procurement models to mitigate the risk to ratepayers.
Instead, Dominion will construct, own and operate the project, with its costs presumed prudent under the 2020 Virginia Clean Economy Act (VCEA) as long as the total levelized cost of energy — including tax credits and the costs of transmission and distribution facilities — does not exceed 1.4 times the cost per megawatt-hour of a simple cycle combustion turbine.
“Every other state that is pursuing large-scale offshore wind is utilizing power purchase agreements or offshore renewable energy certificate contracts, which limits the risks to customers by shifting construction, operational and market risks from customers to the project’s owner,” the SCC noted.
Cost-control Protections
Acknowledging concerns raised by the Office of the Attorney General’s Division of Consumer Counsel, the state Department of Energy, Walmart, Clean Virginia and Appalachian Voices, the commission ordered Dominion to:
file a notice with the SCC within 30 calendar days if it determines that total project costs are expected to exceed the current estimate, or if the final turbine installation is expected to be delayed beyond Feb. 4, 2027. The company currently projects an in-service date by the end of 2026;
include any material changes to the project in each annual Rider OSW update application it files before the project’s commercial operation, and a written explanation for any cost overruns; and
hold ratepayers harmless for the cost of replacement power if CVOW’s energy production fails to meet its projected 42% annual net capacity factor, as measured on a three-year rolling average.
Dominion contended “it would be inappropriate for the company to be put at risk if it fails to meet the capacity factor upon which it has justified and supported this project,” the SCC said. “We disagree. This particular risk for this particular project should not fall on the company’s customers.”
Dominion did not immediately respond to a request for comment on the SCC’s concerns. In a press release, Dominion CEO Robert Blue said the company was happy with the commission’s approval and is “reviewing the specifics of the order, particularly the performance requirement.”
The commission acknowledged that its 42% performance standard will not protect customers from cost overruns or abandonment costs, the latter of which “would not be inconsequential,” the commission warned. “Even if the project is abandoned at the end of 2023, Dominion still estimates it would have prudently incurred approximately $3.7 billion of costs to be recovered from customers.”
The commission warned rising commodity prices and supply chain problems could result in construction delays and cost overruns.
“As a first-mover project, there is no developed supply chain, including equipment suppliers, specialized installation vessels, and infrastructure to handle the transportation and installation of the equipment,” the SCC said. It noted that turbine supplier Siemens Gamesa has suffered supply chain disruptions and that the company has two installations ahead of CVOW that will be receiving the same turbines.
No EPC Contractor
The commission also said the designs for the turbines, monopiles, transition structures and other components have not been finalized and questioned whether Dominion’s 3% contingency estimate ($300 million) was sufficient “for a project of this size and risk.”
“Dominion has also opted not to use an engineering, procurement and construction (EPC) contractor on the project, which the record shows is a departure from how it has managed construction of prior generation facilities. In prior cases, the use of an EPC contractor enabled the company to shift materials, labor and schedule risk away from the company and its customers, as well as risk of construction delays and cost overruns,” the commission said. “In this case, however, Dominion is instead managing the project in-house using multiple interrelated contractors.”
The VCEA declared “in the public interest” the construction or purchase by a public utility up to 5,200 MW of offshore wind. Dominion’s choice of “a construction and ownership model that places most of the risks on customers … is one of the reasons why Clean Virginia seeks an independent assessment of whether the utility-owned model for this project should not be used for the next 2,600 MW tranche of offshore wind,” the SCC said.
Dominion Energy
Effective Sept. 1, Rider OSW will recover financing costs on $661.7 million in capital expenditures during the rate year, as well as allowance for funds used during construction accrued on Dominion’s books.
Like all VCEA-related costs, Rider OSW will be a non-bypassable charge generally paid by all Dominion retail customers — even those who purchase power from competitive service providers — with limited exceptions. “Prior to the VCEA, shopping customers would generally not be responsible for the costs of Dominion generation facilities to the extent they procure for their own energy and capacity from someone other than Dominion. The VCEA now directs that shopping customers pay for VCEA-related costs, with limited exceptions.”
Transmission
The project — 176 14.7-MW wind turbines that Dominion says will produce enough carbon-free power for up to 660,000 homes — will be located 27 miles off the coast of Virginia Beach.
The capital cost includes a projected $1.15 billion for the onshore Virginia facilities, including $774.3 million for transmission-related work and approximately $374.2 million for substation-related work (2021 dollars).
The SCC order approved Dominion’s route for the offshore export circuits and the route for the 4.4-mile underground route for its onshore export circuits from the cable landing to a new Harpers Switching Station. Also approved was an overhead route from Harpers to the existing Fentress Substation.
Transmission upgrades are estimated to be about $215 million. The final costs of transmission network upgrades are unknown because ongoing study work in the PJM generation queue was placed on hold to clear the current backlog.
“The transmission interconnection facilities are a significant component of this project, and [Dominion] has experienced delays and cost overruns on recent transmission projects,” the SCC said.
Jagdmann Suggests Legislative Action
SCC Commissioner Judith Jagdmann | NARUC
In a concurrence, SCC Commissioner Judith Jagdmann observed that CVOW “is a legislatively favored project. If the elements of [the VCEA] are met, the costs of the project are presumed ‘reasonable and prudent’ — which means, in effect, ‘ratepayers pay,’” Jagdmann wrote.
But she said the General Assembly could reduce the impact on ratepayers by making general fund appropriations or authorizing the use of auction proceeds from the Regional Greenhouse Gas Initiative. “Such action may be appropriate given the public policy support for and economic development aspects of this project,” she wrote.
She said the legislature’s requirement for yearly cost recovery proceedings provide “in theory, the opportunity in upcoming sessions to determine if additional steps are warranted to reduce the economic burden that will be placed on Dominion’s customers as the project proceeds.”
“Timing may be of the essence,” she added. “In less than 18 months from now, Dominion plans to have spent close to $4 billion of capital costs on the project.”
The developers of a transmission line intended to carry Wyoming wind power to California have asked to join CAISO, a move that could extend the ISO’s reach more than 700 miles across the West and help the state meet its 100% clean energy mandate by 2045.
But the ISO’s plan to adopt a new participating transmission owner (PTO) model for the line and others like it has raised concerns.
The planned TransWest Express line “intends to place under the CAISO’s operational control all of [its] project transmission lines and associated facilities … that will connect to the existing bulk power system in Wyoming and Utah as well as directly to the [CAISO]-controlled grid in Nevada,” the company said in its application to become a PTO.
TransWest would consist of 732 miles of transmission lines in three linked segments: a 405-mile, 3,000-MW HVDC system between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada. It will connect in Utah to lines serving the Los Angeles Department of Water and Power (LADWP) and in Nevada to CAISO’s grid and balancing authority area.
The project is an “advanced stage of development, focused on pre-construction matters including tower design and testing; interconnections; contracting with engineering, procurement and construction contractors; and financing,” the application says. “All major permits have been acquired, and 100% of the easements/authorizations to build on private lands have been secured.” Major parts of the project could be in service by 2026, it says.
Subscriber Model
TransWest would be CAISO’s first subscriber participating transmission owner (SPTO), a new model that would give the ISO operational control of the lines without increasing its transmission access charge (TAC), currently more than $16/MWh.
Last year, TransWest conducted a FERC-approved open-solicitation process that offered firm, long-term transmission service to California via Utah and Nevada. It decided to allocate 100% of its capacity to Power Company of Wyoming, owner of a 3,000-MW wind farm in the south-central part of the state. FERC approved the arrangement in February.
Both TransWest and Power Company are wholly owned affiliates of The Anschutz Corp., a privately held company based in Denver controlled by billionaire Phillip Anschutz, a conservative who made much of his fortune from oil and natural gas. Anschutz has sought to profit from California’s clean-energy mandate under Senate Bill 100.
To meet the 2045 goal, the state will need to import as much as 10 GW of out-of-state wind by 2040, at least half of it from Wyoming, according to projections by the California Public Utilities Commission and the California Energy Commission.
CAISO’s recent 20-year transmission outlook examined new transmission needed for the undertaking, predicting overall costs of $30 billion that includes $12 billion to carry wind from the Great Plains and Rocky Mountain states. (See CAISO Sees $30B Need for Tx Development.)
Stakeholder Meeting
In an Aug. 1 presentation and stakeholder question-and-answer session, Deb Le Vine, CAISO director of infrastructure contracts and management, described the TransWest project and how the new SPTO model would work.
“In trying to implement a new type of participating TO, there are a number of things to consider,” Le Vine said. “The intent was to go ahead and come up with a model that allows a remote transmission facility to become part of the ISO grid but to have subscribers that would pay for the transmission.”
Most of the transmission capacity for TransWest is subscribed in at least one direction and would not rely on ISO for funding, Le Vine said in her presentation.
Subscriber rights to the line will be treated as encumbrances, similar to existing contracts on transmission lines joining CAISO, she said. An SPTO could recover incremental charges from CAISO market participants using the lines, for instance, if non-subscribers send capacity from south to north on TransWest, she said.
“We’re looking to go ahead and support this concept by an amendment to [CAISO’s] Transmission Control Agreement” (TCA) without tariff changes, she said.
Need More Info?
Some stakeholders felt CAISO needed to provide more information that spells out the details of how the new subscriber model would work and to engage in a stakeholder process, making tariff changes.
Chris Devon, director of market intelligence in the West for advisory firm Customized Energy Solutions and a former CAISO senior policy developer, asked De Vine if the subscriber model would be detailed in a paper or only through slide decks like the one that she used in her presentation.
De Vine said it would be presented through slide decks because the new model does not require changes to CAISO’s tariff, only to its TCA.
Devon said he thought the changes should be vetted in a stakeholder process and made through tariff changes, not through the TCA. He expressed concern with CAISO using an abbreviated process to adopt a complex, untested TO model that diverges from current market practices.
The subscriber model resembles processes being discussed in the ISO’s transmission service and market scheduling priorities stakeholder initiative, Devon said. That initiative is meant to develop a “long-term, holistic framework for establishing scheduling priorities,” the ISO says.
The new model could impact the CAISO market and stakeholders, Devon said. “It just seems to me like this is actually creating a new type of policy as opposed to just being something that should be done through this change to the TCA, so I think it should be stakeholder-ed.”
The subscriber model’s potential costs to ratepayers remains unclear.
Asked to comment, the CPUC, which has been trying to control rising ratepayer bills for the state’s increasingly expensive electric system, said in an email that it is “actively participating on behalf of ratepayers in the CAISO’s stakeholder processes related to the newly proposed subscriber participating transmission owner model concept related to TransWest Express.”
“As such, we are unable to provide a specific comment on the TransWest Express transmission line at this time as we continue to develop our analysis.”
Comments on the Aug. 1 presentation are due Aug. 15. Stakeholders have until Sept. 19 to comment on the TransWest application.
Washington’s first industrial-scale green hydrogen production facility has fallen an additional six months behind its original start date.
The facility near East Wenatchee on the Columbia River in Central Washington was originally set to go online in late 2021. (See Wash. PUD Breaks Ground on Hydrogen Plant.) Supply chain and COVID matters delayed startup to the end of this year or early 2023. Now the plant is expected to commence operation in the summer of 2023, Douglas County Public Utility District spokeswoman Meaghan Vibbert told NetZero Insider in an email.
“We had the usual COVID supply chain issues, bids coming in more than anticipated, and more recently, we have changed course in building design. We had purchased a metal building, but the energy code and safety requirements influenced us to change to a concrete structure, which is slated to go out to bid late this month,” Vibbert wrote.
The project has been working with a roughly $25 million budget, up from an earlier $20 million estimate. Its goal is to produce two tons of hydrogen a day.
The Wells Dam, about 50 miles upstream of East Wenatchee, is the primary power-generating resource for Douglas County PUD. Excess power and water from the dam will eventually be sent to the new hydrogen plant to produce green hydrogen fuel via electrolyzers, which separate the oxygen and hydrogen molecules in water.
While the Douglas PUD has been in talks with several potential customers, no contracts have been signed yet, Vibbert wrote.
Besides providing hydrogen for vehicle fueling stations still in the birthing stage, the plant’s potential future contracts will likely include the steel and ammonia industries. The PUD recently bought an extra 90 acres next to the plant’s 40-acre site to prepare for future expansion if needed.
Washington is seeking to become host to one of four to eight national hydrogen hubs to be funded by $8 billion in U.S. Department of Energy grants. Gov. Jay Inslee and the state’s Department of Commerce have been working this year to coordinate the state’s activities around winning the DOE funding. State lawmakers in March overwhelmingly passed a bill to create a new office to support the development of green hydrogen and other alternative fuels. (See Wash. Looks to Boost Prospects for Winning Hydrogen Hub.)
FERC failed to consider the impact of potential rate increases when it allowed Louisville Gas and Electric (LG&E) and Kentucky Utilities (KU) to partially exit market power mitigation measures, the D.C. Circuit Court of Appeals ruled Friday (19-1236).
The commission imposed rate de-pancaking provisions to resolve horizontal market power concerns after LG&E and KU merged in 1998 and left MISO in 2006. The utility was acquired by PPL (NYSE:PPL) in 2010.
As a condition for allowing the utility to leave MISO, FERC required it to agree not to charge its wholesale power customers duplicative “pancaked” transmission rates for power shipped to or from MISO, so long as the RTO did the same.
In March 2019, the commission agreed the de-pancaking provisions — spelled out in the utility’s Schedule 402 — could be removed because loads located in its market would have access to enough competitive suppliers.
But the commission sought to protect customers that had made business decisions based on the de-pancaking provisions by requiring LG&E and KU not to end de-pancaking during a transition period. It set the transition at 10 years for the cities of Paducah and Princeton, Ky. (P&P), which had invested in the Prairie State coal-fired generator connected to the MISO grid.
The D.C. Circuit said that while “the commission reasonably found that sufficient competition would survive the return of pancaking, it was arbitrary and capricious for the agency to ignore the effect pancaking would have on rates.” It also said FERC failed to adequately explain two aspects of its transition requirements.
While there were no more than seven competitive wholesale energy suppliers for the grid when FERC approved the LG&E-KU merger, by 2018, more than 100 suppliers could competitively sell to the grid, the commission said.
LG&E and KU’s “neighbors include some of the largest independent grids on the continent — MISO and PJM Interconnection LLC — giving those customers ready access to independent power suppliers,” the court said.
But the court said FERC erred in “backhanding the effect that pancaking would have on rates.” It quoted an expert for municipal utilities protected by Schedule 402 who estimated that the end of de-pancaking would raise municipalities’ rates by at least 15%, with one customer’s rates rising 47%.
“Importantly, this rate analysis goes beyond just looking at competition because, as the commission has recognized, markets do not always function perfectly,” the court said. “Yet here, the commission expressly refused to even consider the effect ending de-pancaking would have on electricity rates. The commission held, instead, that because de-pancaking was imposed to protect competition, that was the only factor it needed to consider in ending the program.
“By refusing to consider the material effects of its order on customer rates — a factor that its own regulations identify as a key component of the public interest, the commission engaged in ‘unreasoned, arbitrary and capricious decision-making,’” the court concluded.
The court said that although vacating the commission’s action may cause some disruption, “that disruption seems unlikely to be severe, as our decision implicates in large part the same type of rates that are required to be de-pancaked in the short term under the transition mechanism. We therefore vacate the commission’s decision to permit [LG&E and KU] to end de-pancaking under Schedule 402 and remand for the agency to reconsider its decision in light of the direct and indirect effects ending de-pancaking would have on customers’ rates.”
Win for LG&E/KU
LG&E and KU claimed one victory in the appeal, convincing the court that FERC acted arbitrarily in extending the de-pancaking of P&P’s rates related to their investment in a hydroelectric project until their power agreements expire in 2057.
“That reasoning cannot be reconciled with the commission’s determination that the transition mechanism was meant to extend de-pancaking only for a ‘limited period of time.’ The commission had just said that 10 years of mitigation was enough to protect P&P’s similar long-term investment in Prairie State. Yet here, the commission concluded that mitigation must continue for an additional 38 years — simply because the hydropower agreements contained a concrete end date of 2057.
“That makes no sense. If 10 years of protection suffices for an ownership interest that continues ‘indefinitely,’ something in the neighborhood of 10 years would seem the relevant time frame to protect another exceptionally long investment,” the court said. “The commission failed to explain why the fact that an agreement will terminate by a date certain justified extending the mitigation term for nearly four decades.
“Should the commission conclude on remand that the public interest supports ending de-pancaking under Schedule 402, it must either better explain this aspect of the transition mechanism or take a fresh approach to the question,” the court said.
‘Inexplicable’ Rejection
The court also said FERC’s reasoning for declining to protect the entirety of the Kentucky Municipal Power Agency’s eight-year transmission reservation with MISO was “inexplicable.”
“The commission’s holding that transmission reservations are not ‘separate financial commitment[s]’ meriting independent protection was conclusory and inconsistent with the plain criteria of the transition mechanism,” the court said. “The commission’s competition finding does nothing to justify reaching a different result for transmission reservations than it did for power purchase agreements. The commission’s claim that de-pancaking Energy Agency’s entire transmission reservation would unduly extend its remedy to future power agreements was also baseless. …
“If the commission chooses again to end Schedule 402 de-pancaking on remand, it must come forward with a logical explanation for its decision here that is consistent with the purpose and scope of the transition mechanism, or it must extend de-pancaking on reasoned terms to Energy Agency’s transmission contract,” the court said.
