Duke Energy (NYSE:DUK) put a “for sale” sign on its 3.5-GW commercial renewable business Thursday, saying it wants to focus its capital on regulated spending.
The company has about 5.1 GW of wind and solar in operation, with net ownership of 3.5 GW and a book value estimated at $4 billion. That puts Duke among the top 10 wind and solar operators in the U.S. and has helped it gain experience in renewable energy development and operations that it will rely on in the future.
But the unit represents less than 5% of the company’s profits, generating $46 million in adjusted earnings for the second quarter.
Competition for Capital
“As we look forward to the remainder of this decade and beyond, we have line of sight to significant renewable grid and other investment opportunities within our faster growing regulated operations,” CEO Lynn Good said during the company’s second-quarter earnings call. “We believe this is the right time to step back and really look at the strategic fit of the commercial business, because there’s going to be competition for capital at Duke.”
The company is projecting an adjusted per-share growth rate of 5 to 7% through 2026.
The renewable business includes a pipeline of 1 to 1.5 GW “that could be quite valuable in 2024-2025, in addition to what we had planned for 2023,” Good said.
The company expects to conclude its review by the end of 2022 or early 2023. Sale proceeds would be used to avoid debt and postpone the need for raising equity, Good said.
NC Carbon Plan
The company will need capital, in part, to fund the new solar, battery storage, onshore wind and “hydrogen-capable” natural gas the company wants to add as part of the proposed carbon plan it filed with the North Carolina Utilities Commission on May 16. The plan also seeks permission to begin early development of long lead-time resources needed in the early 2030s, including offshore wind, pumped storage and small modular nuclear reactors (SMRs).
Good said Duke is working on SMRs “in an advisory capacity” by lending its operating expertise. The company operates the largest regulated nuclear fleet in the U.S., producing about half of its power in the Carolinas.
“We do not have an intention of being Version 1 of anything,” she said. “We would like to see a broader adoption of the technologies, a broader understanding of not only operating characteristics, but the commercial attributes — a price — and the ability to construct them within a time frame that we’re comfortable with. And so we see the decade of the 2020s as an important one to continue that work. And if it progresses, as we all hope it does, we would be in a position to potentially invest in one to come into service in the early 2030s.”
Good indicated that neither supply chain problems in the solar industry nor rising natural gas prices have led the company to rethink its coal retirement plans. “Frankly … the logistics of getting coal from point A to point B are also a challenge,” she said, citing labor shortages in railroads and mining companies.
Inflation Reduction Act, Load Trends
Good said the U.S. Senate’s proposed Inflation Reduction Act would benefit the commercial renewables business and save customers money through the nuclear production tax credit. “We will be impacted by the [15%] corporate minimum tax, but we will also benefit from the credits which will pass to our customers,” Good said.
Duke said it expects its 2022 load growth to be above its initial projection of 1.5%. But CFO Steve Young said the company is continuing to project minimal load growth over its five-year planning horizon as it balances the impact of electrification against energy efficiency.
Good said that while the company is basing its spending on assumptions of little additional load growth, migration trends in the Southeast give it “some tailwinds on growth that I think we’ll enjoy for a period of time.”
“But we continue to believe that flat to 0.5% is the best way to manage the business and always hope to be surprised to the upside,” she added.
Q2 Results
Duke reported GAAP second-quarter earnings of $893 million ($1.14/share) versus $751 million ($0.96/share) in 2021. Adjusted earnings were identical to GAAP results for 2022, a drop from $898 million ($1.15/share) for 2021.
Lower 2022 adjusted earnings resulted from higher operations and maintenance expenses from plant outage timing, higher interest costs and the impact of Singapore-based GIC’s 2021 purchase of 11.05% of Duke Energy Indiana.
New England state energy officials are urging ISO-NE to share confidential data about fuel supply and grid reliability with FERC ahead of the upcoming winter.
In a letter to ISO-NE this week, the New England States Committee on Electricity (NESCOE) said it would accept the RTO’s decision not to move forward with a winter reliability or inventoried energy program this year. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)
But the group said that it is “very concerned that the long-known, significant structural issues contributing to winter reliability challenges remain unresolved.”
To that end, it urged ISO-NE to share with FERC the confidential data that drove the decision not to create a winter program this year before the commission holds a forum in Vermont next month to discuss reliability issues in New England. That could include information about “fuel supplies, resource availability, historical resource performance and overall system conditions” to which the public does not have access.
“We understand that your recommendation for this winter rests in part on your confidence in your assumptions about oil and LNG availability over the coming months, which are based on both economic expectations grounded in historical actions and information not available to us or other stakeholders,” the letter says. “Sharing your analysis and the confidential information behind your fuel supply assumptions and recommendation with FERC would be helpful and appropriate given FERC’s regulatory role, ability to receive and protect confidential information, and expressed interest in discussing New England’s winter 2022/2023 outlook.”
The letter comes a few days after the states’ governors wrote to the Biden administration urging it to consider several actions before this winter, including a waiver of the Jones Act for LNG deliveries to the region. (See New England Governors Ask Feds for Help with Winter Reliability.)
The California Energy Commission released an updated draft report this week that would greatly increase the state’s offshore wind goals to 25 GW by 2045, potentially doubling anticipated long-term capacity in response to urging by stakeholders and Gov. Gavin Newsom.
The draft report proposing the targets stemmed from last year’s Assembly Bill 525, which required the CEC to “evaluate and quantify the maximum feasible capacity of offshore wind … [and to] establish megawatt offshore wind planning goals for 2030 and 2045.” The effort is intended to contribute to the state’s goal under Senate Bill 100 to supply all retail customers with 100% clean energy by 2045.
A prior draft of the report in May proposed goals of 3 GW by 2030 and 10 to 15 GW by 2045, but critics contended those goals were too conservative, and the CEC re-evaluated its estimates.
In its latest draft report published Aug. 1, the commission considered stakeholder comments and a July 22 letter from Newsom to the chair of the California Air Resources Board in which he urged “bolder action” to address the urgency of climate change.
“In the letter, among other requested actions, the governor asks the CEC to establish an offshore wind planning goal of at least 20 GW by 2045 and to work with the state’s federal partners to accelerate the deployment of offshore wind, noting that California is home to one of the best offshore wind resources in the world and that offshore wind can serve as a clean, domestic source of electricity that can play an important role in meeting the state’s growing need for clean energy,” the draft report said. “The Energy Commission factored this climate urgency and the call for at least a 20-GW goal into these proposed revisions.”
Soon after the CEC released its first draft report in May, the federal Bureau of Ocean Energy Management issued a proposed sale notice for five lease areas off the California coast, a major step toward BOEM auctions expected this fall and the eventual development of the first offshore wind farms on the West Coast.
Two of the proposed lease areas in the proposed sale notice are in the Humboldt Wind Energy Area off the coast of Northern California, near the city of Eureka. Three are in the Morro Bay Wind Energy Area off Central California, about halfway between Los Angeles and San Francisco. Together, the wind energy areas (WEAs) cover 583 square miles and have the potential to generate at least 4.5 GW of electricity, enough to power 1.5 million homes.
In raising its 2030 offshore wind goals to 3 to 5 GW, the CEC said the “upper end of this range could come from a full build-out of the Morro Bay Wind Energy Area or a combination of a partial build-out of the Morro Bay WEA and Humboldt WEA,” which will require development of a wind port in Humboldt Bay.
“The lower end of that range reflects an understanding that achieving a 2030 online date for any proposed offshore wind project will take a significant mobilization of effort and resources, and timely infrastructure investments, among other factors,” it said. “The CEC will work with state and federal partners to identify process steps and milestones that could allow for a 2030 online date for California’s first offshore wind projects.”
The higher 2045 targets “are designed to be potentially achievable but aspirational and are established at levels that can contribute significantly to achieving California’s climate goals,” the report said.
“These preliminary planning goals may be refined as part of completing the strategic plan as more information becomes available from the analysis of suitable sea space and potential impacts on coastal resources, fisheries, Native American and Indigenous people, and national defense, as well as other strategic plan topics,” it said.
The CEC is scheduled to vote on the revised goals in its business meeting on Aug. 10.
Proponents praised the higher targets.
“These goals set an ambitious course and show California is very serious about ‘going big’ on floating offshore wind to strengthen and diversify its clean power portfolio,” Adam Stern, executive director of trade group Offshore Wind California, said in a statement. “We’re determined as an industry to work closely with state and federal agencies and other stakeholders to ensure the high end of these goals becomes a reality.”
Exelon (NASDAQ:EXC) said Wednesday that the proposed 15% minimum corporate income tax included in the Democrats’ energy and climate bill could impinge its cash flow and slow infrastructure investments, while PPL (NYSE:PPL) said the change would not affect it significantly.
The companies commented on the proposed Inflation Reduction Act of 2022 during their respective second-quarter earnings calls.
Exelon CEO Chris Crane praised the bill’s extended tax benefits for solar and wind and its new ones for nuclear and hydrogen, as well as its measures to support energy efficiency and electrification.
But he said the incentives could be undermined by the new minimum tax and “slow the investment needed to make this [low-carbon] transformation.”
“As currently drafted, we could see an impact of … approximately $300 million per year starting in 2023. Higher taxes would ultimately limit our ability to invest in infrastructure needed to accommodate the clean energy our customers want,” Crane said, adding that the company and its trade group, the Edison Electric Institute, is lobbying for “language that better aligns incentives to achieve” decarbonization.
CFO Joseph Nigro declined to say whether the alternative minimum tax (AMT) would increase the company’s equity needs, saying the company would determine a response during its end-of-year planning. “It’s unclear at this point how these taxes will flow through to our customers,” Nigro said.
The company reiterated its previously announced plans to raise $1 billion in equity by 2025, half of it this year, in part to pay down short-term debt from the Feb. 2 spinoff of Constellation Energy (NASDAQ GS:CEG), its former generation unit.
Crane said the company could resort to cost cutting and adjusting project schedules to maintain its capital spending plans and earnings metrics despite the tax.
“There’s a few balls in the air that we’ll have to … juggle. But we’d rather have the fix to the bill so we’re not having to juggle this,” Crane said. “We’ll see how we prevail as an industry as we go forward.”
No Unity
The industry does not appear united on the minimum tax, however.
At PPL’s earnings call later Wednesday, company officials said they did not expect the AMT to have a material impact.
“As you know, we are now a federal cash taxpayer,” CEO Vincent Sorgi said in response to an analyst’s question. “So, we’re not anticipating the 15% AMT provision to have a significant impact on our business. … No real headwind there.”
CFO Joe Bergstein said the company’s effective tax rate is currently about 15%.
PPL CEO Vincent Sorgi | PPL
Sorgi said the IRA is a net positive for PPL, particularly as it looks to replace 1,000 MW of coal-fired generation in Kentucky by 2028 and meet Rhode Island’s newly enacted 2033 target for 100% renewable energy. In a solicitation that closes in mid-August, PPL’s Kentucky utilities said they would consider replacing the coal generation with renewables, battery storage, and peaking or baseload natural gas. PPL completed the acquisition of Rhode Island Energy in May.
“The ability to elect the production tax credit instead of the [investment tax credit] for solar will improve the economics of our self-build options as we look at renewables as a potential source of replacement generation in Kentucky,” Sorgi said. “In addition, the extension of the renewable tax credits should lower the cost of renewables overall. …
“The transferability provisions around tax credits also makes it more likely that renewables will be built,” he added. “And that’ll also be good in general for the industry and for accelerating our clean energy transition. It simplifies the structure of the deals significantly.”
EEI told RTO Insider on Wednesday that it welcomed the bill’s “robust clean energy tax package.”
But Eric Grey, EEI’s vice president of government relations, did not directly respond when asked whether the group was seeking changes to the AMT.
“As always, EEI continues to be a resource for policymakers seeking feedback on how provisions in this legislation would impact electric companies and their customers during implementation,” Grey said in a statement.
PPL said EPA’s proposed “good neighbor” rule, expected to take effect late 2022 or early 2023, could require shifting the retirement of an additional 500 MW of coal generation from a planned 2034 shutdown to the “2026 to 2028 time frame.”
The rule would require EPA and states to address interstate transport of air pollution that affects downwind states’ ability to attain National Ambient Air Quality Standards. Based on the final rule, PPL will determine whether to retire the plant or invest in “back-end technology” to keep it operating until 2034, Sorgi said.
Earnings Results
Exelon reported GAAP net income from continuing operations of $962 million ($0.47/share) for the second quarter, up from $808 million ($0.33/share) a year earlier. Adjusted (non-GAAP) operating earnings were $935 million ($0.44/share), up from $842 million ($0.36/share).
Nigro said 2021’s second quarter reflects a 9-cents/share impact for corporate overhead costs that were previously allocated to the company’s generation segment and were required by accounting rules to be presented as part of Exelon’s continuing operations. “These costs were paid for by generation and are not indicative of our corporate overhead post-separation,” he said.
PPL’s second-quarter GAAP earnings were $119 million ($0.16/share) versus $19 million ($0.03/share) in 2021. Non-GAAP earnings from continuing operations were $222 million ($0.30/share), compared with $147 million ($0.19/share) the year before.
Entergy (NYSE:ETR) easily beat analysts’ expectations with its second-quarter results Wednesday, thanks to better-than-expected retail sales during the early-summer heat.
The company reported earnings of $160 million ($0.78/share) for the quarter. A year ago, the company disclosed a loss of $6 million ($0.03/share).
The New Orleans-based company’s adjusted earnings of $364 million ($1.78/share) far exceeded Zacks Investment Research’s consensus estimate of $1.42/share.
“We had a productive second quarter,” CEO Leo Denault said in a statement.
Denault said Entergy had reached a settlement valued at $300 million with the Mississippi Public Service Commission over performance and accounting issues at its 1.43-GW Grand Gulf nuclear plant in the state. The agreement was designed as a global settlement to resolve all disputes between FERC and Entergy subsidiary System Energy Resources Inc., the plant’s majority owner. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)
Arkansas regulators and the New Orleans City Council rejected or opted out of similar settlements this week. The Arkansas Public Service Commission said Entergy’s “low-ball” offer did not include a cash refund for Entergy Arkansas’ customers, as did the Mississippi settlement.
Denault told financial analysts during the company’s earnings call Wednesday that the Mississippi commission “recognized the opportunity to deliver meaningful value to customers today, rather than wait for an uncertain outcome potentially years down the road.”
A FERC decision is expected later this fall.
Grand Gulf sells most of the output at wholesale to Entergy’s Arkansas (NYSE:EAI), Louisiana (NYSE:ELC), Mississippi (NYSE:EMP) and New Orleans (NYSE:ENO) operating companies, but it has been the subject of complaints for overcharges because of poor plant operations and incentive pay to company executives. The plant has been offline for several weeks to repair mechanical issues, Entergy said.
Denault said completing the sale of Michigan’s Palisades Nuclear Plant in May to Holtec Decommissioning International represented the “last major milestone” in exiting the merchant nuclear power segment. (See Federal Aid Likely Too Late to Save Palisades, Diablo Canyon Nukes.)
Entergy’s share price closed Wednesday at $117.38, up $2.27 (1.97%) from the previous closed.
Staring down the possibility of fuel shortages this winter, New England’s governors are asking the Biden administration for help, including a possible waiver of the Jones Act for LNG deliveries to the region.
In a letter to Energy Secretary Jennifer Granholm dated July 27, the six governors in the region warned that price volatility because of the war in Ukraine will have “have significant implications for our region’s electric and natural gas customers and raises reliability concerns if the region suffers a severe winter.”
New England relies on LNG for both electricity generation and heating in the winter, as domestic natural gas capacity is constrained.
The new letter follows increasingly vocal warnings from ISO-NE and a back-and-forth between it and the states over how to prepare for the possibility of extreme cold that could strain the electric grid.
Despite its alerts about the precarious state of the grid in winter, ISO-NE recently determined that no out-of-market solutions to make sure that generators stockpile fuel would be appropriate for this winter because of their cost and unclear benefits. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)
The states are turning to the federal government with three distinct asks.
First, they request that the administration begin “to explore the conditions under which it might be appropriate to suspend the Jones Act for the delivery of LNG for a portion or all of the winter of 2022-2023.”
The letter notes that the law, which requires that ships hauling cargo between U.S. ports be built in the U.S., “effectively precludes all U.S.-exported LNG from being delivered into New England.”
The governors also asked that the Biden administration consider utilizing the Northeast Home Heating Oil Reserve and consider developing a “new or modernized strategic energy reserve to protect against low-probability weather events to ensure energy system reliability.”
And third, the letter asks that the federal government and the states “commence coordinating immediately to monitor the developments as winter approaches.”
The issues facing New England’s system aren’t likely to disappear overnight, the states acknowledged.
“While our immediate focus is on this upcoming winter, the ramifications of Russia’s invasion and the realignment of natural gas supplies will have long-term global consequences and could have adverse impacts in New England,” the letter says, calling for an expanded energy strategy and construction of new critical infrastructure.
“It’s really important that we have active and direct collaboration and communication going on among all of the entities that have a role to play in ensuring our grid is reliable for consumers in New England,” Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, told RTO Insider on Wednesday.
“We’re in a really unprecedented time with the war in Ukraine and supply chain disruptions and volatile commodity prices falling out of the pandemic,” Dykes said. “We know how this is affecting consumers already in terms of energy costs, and we’re keenly aware of the unique vulnerability of the New England electric grid.”
FERC is holding a forum in Vermont in September to examine the challenges facing New England’s grid reliability in winter.
The New Hampshire Department of Environmental Services (DES) released a draft solid waste management plan Monday that includes a goal of considering climate change in all management planning and decision-making.
Efforts to reach the state’s goal of reducing solid waste disposal 45% by 2050 will have indirect benefits related to the reduction of greenhouse gas emissions, DES said in the plan. New Hampshire set a non-binding emission reduction goal in 2009 of 80% below 1990 levels by 2050, and a bill to establish more stringent reduction targets did not make it through the legislature in this year’s session.
Recycling and food waste diversion practices are two areas the department said could support state climate goals by reducing energy use and associated emissions and reducing methane emissions from food in landfills. In addition, the department said the buildout of local diversion markets would reduce transportation emissions.
Gov. Chris Sununu signed a bill last summer that found New Hampshire “lags behind” in waste reduction and recycling policies and established a solid waste management working group to help DES develop a long-range management plan.
The state’s draft 10-year plan is based on priorities set in 1990 by the legislature that emphasize reducing waste generation at the source and increasing recycling and composting. Despite those priorities, DES said the state’s waste management infrastructure has not shifted significantly from disposal to the preferred management methods over the last 30 years.
“Even though landfilling represents the least preferred method … landfills comprise a significant portion of New Hampshire’s overall waste management capacity,” DES said.
There is no ban on food waste and common food packaging in New Hampshire landfills, but the department recommended in the plan that the state “explore” such legislation. The plan also recommends consideration of legislation that would update state agencies’ procurement policies to prioritize products with “high post-consumer recycled content.”
The department is accepting comments on the draft plan through Aug. 26 and will publish a final version Oct. 1.
The global floating offshore wind (FOSW) development pipeline has grown 228% since the last quarter of 2020, reaching 115.9 GW, according to The Renewables Consulting Group’s 2021 Global Offshore Wind Annual Market Report.
New FOSW capacity that is operational, secured or in development, including capacity that is scheduled for auction, has reached 116.2 GW, the report said. Of the new development capacity, 4.9 GW is attributed to the U.S., where the Bureau of Ocean Energy Management is planning lease auctions in California that would unlock at least 4.5 GW of FOSW capacity.
That planned capacity puts the U.S. eighth in the world in terms of national FOSW pipelines, with the U.K. and Sweden taking the No. 1 and 2 slots at 20.9 GW and 18 GW, respectively.
Industry studies of the global pipeline generally expect between 5 and 12 GW reaching commercial operation by 2030, with the remaining capacity coming online post-2030, Dan Kyle Spearman, director and global lead for floating wind at RCG, told NetZero Insider.
RCG analysis expects that West Coast FOSW projects could come online by 2030. Given the nascent status of the FOSW market, those projects looking to deploy by 2030 will be relying on a growing and risky supply chain.
A lot needs to happen by 2030 for the FOSW market to “pump out the big projects,” Spearman said, including identifying the most cost-effective and reliable floating platforms. “We have a database of over 100 different floating wind platform designs, which is madness.”
The market needs to winnow those designs down to a handful that can use the same supply chain and work in an industrialized, modularized process, he said.
Building a domestic FOSW supply chain for the early West Coast projects will bring a complex set of challenges.
“The West Coast is particularly difficult because you don’t have the history of either big ship building or oil and gas,” like on the south and east coasts, he said. That limits the ability of existing ports to service projects in the near term.
Developers will have to be clever about the construction process, according to Spearman. That might include finding alternatives to the current construction approach that favors erecting turbines on their platforms at port and towing them to the project site.
“It’s quite challenging actually to tow a platform long distances with a turbine fully erected because you get quite significant fatigue in areas such as your tower,” he said. If, for example, construction for Morrow Bay projects were to occur in Humboldt Bay, towing the platform approximately 500 miles to Morrow Bay would test the tower’s structural integrity.
The West Coast’s very deep waters of between 900 and 1,200 meters will also present challenges for the platforms’ mooring system design and required supply chain.
“It’s not insurmountable, but there will be a cost to installation,” Spearman said.
The process of sorting out which of the major platform designs the market will choose to invest in likely will come down to geography, cost and the capabilities of local suppliers.
Designs that are suitable for harsh, deep-water conditions on the U.S. West Coast also might be suitable for projects such as in Australia, Spearman said. Currently, semisubmersible technologies are the “most preferred choice,” but Spearman says he would not rule out a tension-leg-platform (TLP) design. TLP is a “very attractive technology because you can reduce your steel weight,” which is beneficial at scale.
If the U.S. is unable to build a robust domestic FOSW supply chain by 2030, developers will be forced to compete for components internationally against developers in more mature markets.
While there will be a strong opportunity for U.S. domestic component supply to develop, Spearman said, there will be uncertainty about the price point developers will be “willing or forced to pay.”
Ultimately, policy will influence supply chain development and the choice between low-cost energy and a thriving domestic economy.
“Developers can go either way, but if they are left with no policy framework, they’ll just go for the lowest [component] option, and local suppliers are just not going to be able to compete,” Spearman said.
The U.S., he said, will need a policy framework in place to build a joint business case for developers and the supply chain.
Maryland has identified 502 “optimal” locations where it might install electric vehicle charging stations over the next five years, using the $63 million it is slated to receive from the Infrastructure Investment and Jobs Act (IIJA).
Maine is proposing a staged approach to deployment of DC fast chargers, focusing first on the more populated Southern part of the state, and then building out to the central and Northern regions. | Maine Dept. of Transportation
But according to the plan the state recently filed with the Federal Highway Administration (FHWA), not all of the sites are within one mile of key highways, as the funding guidelines require.
Maryland is also one of several states raising concerns about whether its electric system will be able to interconnect and integrate multiple charging stations, each with four 150-kW DC fast charging ports, which are also required under the National Electric Vehicle Infrastructure (NEVI) program established by the IIJA.
“Upgrades needed to both the line and load side to meet this increased demand could be extremely costly, especially in areas where the infrastructure may be limited,” the plan said. But the plan also includes a basic assumption that installation costs to be covered with federal funds could include system upgrades as needed.
Maine’s proposed solution to the problem, laid out in its plan, is a staged approach. The initial stage would see the state install charging stations with four 150-kW ports at high-traffic sites, mostly in the southern part of the state. Medium- and lower-traffic sites in the middle and northern regions will only get two 150-kW chargers, at least to start.
Monday was the deadline for all 50 states, Puerto Rico and the District of Columbia to file their NEVI plans with the FHWA, and the agency reported on Tuesday that all had met the deadline. The FHWA now has until Sept. 30 to review and approve the plans.
North Carolina currently has 10 NEVI-compliant charging locations in the state. | North Carolina Dept. of Transpor
The program will provide a total of $5 billion in formula funding to the states over the next five years, with the goal of building out a national network of 500,000 chargers that will make EV charging safe, convenient and affordable. (See Biden Administration to Order EV Charging Standards.)
Still, like Maine and Maryland, many states have raised concerns about their ability to meet all the program guidelines and may be asking for “exceptions” to allow them to get their plans approved and start receiving funds. (See EV Charging Standards Leave Some Obstacles Untouched.)
The exception process is intended to provide states with flexibility on some of NEVI’s core requirements, said Steve Lommele, a senior project manager with the Joint Office of Energy and Transportation (JOET) launched by the Energy and Transportation departments earlier this year to help states with their plans. For example, under the NEVI guidelines, the IIJA-funded EV chargers must be installed every 50 miles along interstate highways, and no more than one mile off these routes.
California, which did not identify specific exceptions in its plan, asked that the FHWA allow for exceptions to be requested at any time throughout the NEVI program. “Flexibility in requesting exceptions will be especially important in the rural areas of the state,” the plan said.
Washington will initially prioritize EV charger buildout on it heavily traveled I-5 and I-90 corridors, while making areas in the east secondary priorities. | Washington State Dept. of Transportation
“There are certainly sections of rural highway, particularly in the Western United States, where there might not be much at all along a 50-mile stretch of highway, Lommele said during a recent webinar on state planning for NEVI, sponsored by the nonprofit Advanced Energy Economy (AEE). “So, it might be worth considering expanding that to 55, 60 or 70 miles.
“There might be a town with amenities that’s a bit further than one mile from the highway, and so states are, in some cases, requesting exceptions because we want these to be convenient locations that have amenities,” he said.
Renee Samson, director of regulatory affairs at FreeWire Technologies, an EV charger manufacturer, raised yet another concern during the AEE webinar that “sites that may not be able to support four charging [ports] or have no economic need or do not have enough EV drivers.” Echoing Maine’s approach, she said, such locations “might be better suited to have one to begin with and then work towards that goal” of having four ports.
Lommele said the JOET and most states have been working closely with utilities to develop strategies for deploying increasing numbers of DC fast chargers in the coming years. “It really starts with close collaboration and working together to understand where the infrastructure is going to go, where maybe some stations will be more difficult,” he said.
“By and large, states are probably going to be focusing on the lower hanging fruit to start, the areas where there may be less significant challenges, and then, as we kind of develop best practices and learn from deployments, using that information to inform investment in the later years,” he said.
An FHWA spokesperson also stressed that “these plans will be updated annually, and the build-out of a national network will continue to evolve over the coming several years. But we are confident that we will have a truly national and publicly available EV charging network that builds consumer confidence in the growing number of EVs that automakers are offering.”
Changing NEVI Requirements
Installing the fast chargers every 50 miles on major interstate routes is the top priority for the first round of NEVI funds, creating a national network of Alternative Fueling Corridors, or AFCs. But previous guidelines for AFCs, set before passage of the IIJA, allowed for fast chargers of less than 150 kW and as far as five miles off a corridor, rather than one mile. The current guidelines were issued in February and further updated in June.
California already has an extensive network of public EV chargers in populated areas. | Caltrans
In addition to the 50-mile and 150-kW requirements, the June updates also require fast chargers to be available 24/7, operating 97% of the time and able to accept any debit or credit card. The program also requires states to contribute 20% of the cost of building out the charging stations on their AFCs.
These updates have meant some states needed to quickly rethink their plans. Slated to receive $21.1 million in NEVI funds, Vermont already had a plan for putting fast chargers along its highways based on the previous federal guidelines. As a result, the state currently has no locations with more than two 150-kW ports, and fast charging stations that the state has funded and built along its AFCs mostly have two 50-kW plugs.
Further, of the 15 sites for NEVI charging stations identified in Vermont’s plan, four will fall outside the one-mile zone and may need to apply for exceptions.
With 565,000 EVs on the road, California is the country’s leading EV market and will get $384 million in NEVI funds over the next five years. The state has already installed 28,877 public Level 2 chargers and 6,764 public fast chargers, but only 592 fast chargers within one mile of a key highway exit are 150 kW, according to figures in the state’s draft NEVI plan.
Fast charging stations installed on the state’s highways “before the NEVI requirements were introduced … may serve as prime locations and critical sites to be upgraded,” the plan says. In addition, fast charging sites that were developed with funds from the California Energy Commission must be wired to accommodate 150-kW chargers, the plan says.
California is planning a competitive bidding process in which developers will be asked to identify potential sites for NEVI-compliant charging stations “based on an analysis of gaps in the current network, future charger needs and geography,” as well as the minimum NEVI requirements, the plan says.
‘Fail Early and Often’
With nearly $408 million in federal funds, Texas took a different approach to NEVI planning, starting without an existing EV policy blueprint, said Ryan Granger, a strategic planning manager at the state’s DOT, also speaking at the AEE webinar.
Ohio only has 10 charging stations that are NEVI-compliant but is analyzing highway interchanges across the state to identify additional sites. | Ohio Dept. of Transportation
“We didn’t have any state goals. We were able to focus on the [federal] requirements in the plan and getting that done,” he said. “We wanted to fail early and often and learn from people telling us what we were doing wrong.”
Like Maine, Texas is planning for a phased rollout of EV charging infrastructure, with an initial focus on AFCs, adding 55 new sites to 27 preexisting charging stations installed by private companies, Granger said. In subsequent years, the state will target installing charging stations in rural counties, small urban areas and county seats, which, Granger said, “are pretty centrally located.”
In states with smaller, still-developing EV markets, such as Ohio, the process for identifying charging sites begins with an analysis of highway interchanges with existing electric infrastructure that could support four 150-kW chargers, the state’s plan says. With only 10 NEVI-compliant DC fast charging stations at present, Ohio is looking for interchanges with one or more truck stops, one or more retail centers or big box stores, or three or more gas stations or convenience stores.
Potential sites meeting those criteria are then analyzed by the local utility to “confirm the sites are viable or [have] capacity constraints that would add costs,” the plan says.
In Ohio, which is eligible for $140 million in NEVI funding, the state’s DOT had “an initial conversation” with the state’s utilities, said Luke Stedke, managing director of communications and policy, “overlaying our sites with their grids.”
How the utilities will meet the future demand from DC fast chargers is something each utility will have to develop with the Public Utilities Commission, he added.
FreeWire’s Samson also cautioned that states and utilities will need to provide developers with appropriate pre-application information to ensure that a site will be able to connect to the grid and not get caught in a long interconnection queue.
“Handling the utility connection upfront and showing that a site will indeed be able to be built out is going to be important for ensuring that there’s a smoother process than what it potentially could be,” she said.
Facing Workforce Shortages
Beyond geography and the grid, another common theme across many state plans is the need for workforce development. California has estimated that its existing statewide goals for light-, medium- and heavy-duty EVs and associated infrastructure will require a charging installation workforce of 47,300 to 71,500 job-years ― the equivalent of one person working a full-time job for one year ― over 2021-2031.
The state is tapping into a range of partnerships, including an apprenticeship program “for new and innovative sectors,” run by the Foundation for California Community Colleges. The state has also developed on-the-job training programs focused on EV supply equipment installations and service, including basic safety training.
Oregon, slated for $52 million in funding, also sees the NEVI program as a “significant opportunity” for workforce development, but the state’s plan acknowledges “there is insufficient qualified labor to complete these deployments, especially when considering certification requirements.”
The plan says the state’s DOT is in discussions with utilities and unions regarding the status of the local certified workforce and workforce development needs.
Samson pointed to the Electric Vehicle Infrastructure Training Program (EVITP), a national program to certify electricians to work on installing EV chargers. Some states are requiring that charging stations be installed by EVITP-certified electricians when “there simply aren’t enough electricians that are certified in certain areas of the country. … Making [it] a requirement is going to add complexity and expense to a project when you have to have electricians travel quite some distance to do installations,” she said.
California’s plan noted that, as of May, large areas of the state served by AFC-designated highways had no local contractors appearing on the state’s EVITP published list. To reduce the risk of a shortage of needed electricians, the California Energy Commission will contract with community colleges to expand the locations of in-person EVITP examinations outside the San Francisco and Los Angeles areas.
Workforce training may also be critical for state plans to meet federal “Justice 40” requirements that 40% of the benefits of federally funded projects go to disadvantaged communities. As noted in California’s plan, AFCs don’t, in general, run through or close to disadvantaged or low-income areas, either in dense urban areas or more remote rural regions.
Lommele of JOET said that “one aspect of [NEVI] benefits could be creating workforce opportunities for disadvantaged communities.
“States are engaging with disadvantaged communities to understand what benefits are important, what needs those communities have and how the program can support that,” he said.
The IIJA also provides $2.5 billion for competitive, discretionary grants to fill the gaps in EV charger infrastructure not covered by the NEVI formula funds. Guidelines for those funds are expected later this year, the FHWA said, and will further build out the national network by making investments in community charging.
“The NEVI formula program is really intended to be a backbone of a national network,” Lommele said. “It’s going to continue to require additional public and private investment to meet the needs five years from now, but we’re really working toward a future where everyone can ride and drive electric.”
[EDITOR’S NOTE: A previous version of this story incorrectly called Jonathan Booe the CEO of NAESB. He is COO.]
FERC Chairman Richard Glick and NERC CEO Jim Robb last week asked North American Energy Standards Board (NAESB) leaders to convene a forum to discuss plans to improve natural gas reliability in support of the electric sector and address challenges from gas-electric interdependency.
The request came Friday in a joint letter to NAESB COO Jonathan Booe and Chairman Michael Desselle. It was inspired by the FERC-NERC joint report on the winter storms that hit Texas and the Midwest in February 2021, leading to widespread generation outages, derates or failures to start that caused more than 23 GW of manual firm load shed. (See FERC, NERC Release Final Texas Storm Report.)
The report, released in November, found that natural gas facilities accounted for more than 50% of generation failures, both in terms of the number of units and their total nameplate capacity.
Among the report’s recommendations was that FERC establish “a forum in which representatives of state legislatures and/or regulators with jurisdiction over natural gas infrastructure, in cooperation with [other stakeholders], identify concrete actions … to improve the reliability of the natural gas infrastructure system necessary to support the Bulk Electric System.” Glick and Robb’s letter said that NAESB “is uniquely positioned” to organize such a forum, having “representation from all segments of the supply chain” in the gas and electric markets.
Speaking to ERO Insider on Monday, Booe said the organization was “excited to see the request” and had been “working through the weekend” to develop a response to the letter. While NAESB is not ready to schedule the forum yet, Booe observed that it has many years of experience working to address gas and electric market coordination issues, several times at the request of FERC and often with support from NERC and other stakeholders.
“We know it’s going to be a challenge, but we have faced similar challenges in the past,” Booe said. “So, I think that’s why the commission and NERC, with the support of NARUC [National Association of Regulatory Utility Commissioners], have put their confidence in us to help establish this forum and try and address some of those findings that were in the report … We have this long history of convening these kinds of diverse groups of interested parties and trying to find consensus positions.”
NAESB has pursued its own response to the February storms, including initiating a standards project aimed at improving gas and electric coordination last December. (See NAESB Starts Gas-electric Coordination Project.) Asked about the progress of this effort on Monday, Booe acknowledged that action had stalled after NAESB was unable to “find consensus from our groups” about the appropriate direction of the project. However, he said the request from Glick and Robb might inspire fresh movement toward new standards from the organization.
NAESB President Rae McQuade told ERO Insider she expected members from across both industries, as well as the regulatory community, would be happy to contribute to the forum, whatever form it takes.
“We have always worked very closely with NARUC, and we’ll certainly do so on this as well,” McQuade said. “And we’ve also got every segment of the wholesale and retail natural gas and electric market representatives as NAESB members. So, I’m sure that a number of our members will be very interested in participating, as well as others.”