Decarbonization

The Federal Energy Regulatory Commission on July 27 approved a rule to speed up clogged interconnection processes that have left power generation and energy storage projects waiting years for permission to connect to the grid.

"Today is a historic day," FERC acting Chairman Willie Phillips said during a media briefing. “This rule will ensure that our country's vast generation resources are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.” 

The rule, called Order 2023, is the first major change to FERC’s interconnection requirements in two decades.

Interconnection queues around the country grew 40% in 2022 compared with the year before, with more than 10,000 projects — representing 1,350 GW of generation and 680 GW of storage — waiting for approval to connect to the grid, the Lawrence Berkeley National Laboratory said in an April report. The vast majority of the planned projects are solar, storage and wind.

The typical project built in 2022 took five years from its interconnection request to commercial operations, up from three years in 2015, according to the report.

“We've seen long [interconnection] wait lines, which is hurting our reliability, hurting our resilience, and raising costs for all customers,” Phillips said. “This rule is a major first step in our journey to addressing transmission reform.”

Largely following a proposal issued last year, the rule adopts a “first-ready, first-served” cluster study approach for examining what grid upgrades may be needed to safely bring a generator or storage project online. That process will replace the practice of studying individual proposals on a first-come, first-served basis.

In a move aimed at weeding out speculative projects that have little chance of being built, FERC is requiring increased financial commitments for interconnection customers to enter and remain in interconnection queues, Tristan Kessler, an economist with FERC’s Office of Energy Policy and Innovation, said during a presentation on the rule, which hadn’t been released as of the morning of July 28.

It requires interconnection customers to pay increased study deposits, meet more stringent site control requirements and pay commercial readiness deposits, Kessler said.

The rule also sets firm deadlines for regional transmission organizations and other transmission providers to complete interconnection studies, according to Kessler. It imposes penalties if the deadlines are missed.

The rule reflects advances in technology, such as solar paired with battery storage, to share an interconnection point. It requires transmission providers to consider grid-enhancing technologies when assessing what upgrades may be needed to bring new generation online. It also sets modeling and “ride-through” requirements for solar and other nonsynchronous generators to bolster grid reliability.

Grid operators already use some measures in the rule, but none use all of them, Phillips said.

Transmission operators will have 90 days after the rule is published in the Federal Register to file plans at FERC explaining how they will put the rule in place.

Rule draws praise

The rule represents “significant progress” toward interconnection reform, according to Adam Stern, senior manager for regulatory affairs at Enel North America, a renewable energy developer.

In a change to the proposed rule, FERC adjusted commercial readiness milestones so they line up with typical project timelines, he said in a July 27 email.

The rule codifies best practices that are already used in many interconnection queues, but it is too soon to know how effective it will be at speeding up those reviews, according to Stern.

“We will have to wait and see how the compliance process goes and how RTOs and public utility transmission providers expect to meet the requirements of the rule,” Stern said.

While the rule is “meaningful,” it doesn’t instantly fix the interconnection backlog, Victoria Lauterbach, a partner at the law firm Foley Hoag, said July 28 in an email. Even so, a first-ready, first-served cluster approach will likely ease interconnection backlogs in regions that are not using that process, she said.

Transmission providers will be able to deviate from the final rule to reflect regional reliability characteristics, their independent judgment, or if they have a provision they show is at least as good as the rule, Lauterbach said.

Lauterbach highlighted as “significant reforms” the requirements that transmission providers allow projects to be co-located behind an interconnection point and to share a single interconnection request, and that in some cases a resource can be added to an interconnection request without it being deemed a “material modification” that could move it back in the queue.

“These practical reforms should provide greater freedom for developers of projects to structure their interconnection plans in efficient ways that work best for their own unique facility and site characteristics,” she said.

More to do

Various groups said the reform rule was a good first step at reducing interconnection queue backlogs, but that more needs to be done.

“The order does not address some of the root causes of mounting interconnection costs and delays, including an unnecessarily protracted and inefficient study process and unexpectedly high costs of transmission system upgrades, which are ultimately passed through to consumers,” Caitlin Marquis, Advanced Energy United managing director, said in a statement.

Enel’s Stern said that “We must prioritize creating certainty for generators, starting by ensuring interconnection studies reflect real-world operations and least-cost solutions and requiring better coordination between the interconnection and transmission planning processes.”

The interconnection reform package is “underwhelming,” according to Devin Hartman, director of energy and environmental policy at the R Street Institute, a free market think tank.

“The new status quo will still leave years worth of interconnection backlogs, keep grid upgrade costs at multiples of what is necessary, and delay new supply needed for grid reliability and clean [energy] transition,” Hartman said in an email. 

FERC should prioritize supplemental efforts to tackle remaining interconnection issues, he said.

Phillips said he expects the interconnection reforms will “significantly” speed up the process, but “there is so much more to do.”

FERC is working to release a rule reforming transmission planning and cost allocation in the “coming months,” he said.

“Together, this interconnection queue reform, with long-term regional planning, [means] we will have the greatest transmission reforms in a generation to come out of FERC,” Phillips said.

A failure to speed up transmission expansion in the United States “severely” limits potential wind, solar and energy storage projects, cutting possible greenhouse gas emissions reductions roughly in half, according to a Princeton University-led REPEAT Project report.

The report released July 13 is the research team’s latest analysis of how the Inflation Reduction Act and the Infrastructure Investment and Jobs Act could affect the climate and the U.S. energy system.

The researchers estimate that under existing law, the U.S. will reduce its economy-wide carbon emissions to 4 billion tons to 4.2 billion tons in 2030, or by about 37% to 41% from 6.7 billion tons in 2005, short of the Biden administration’s 50% to 52% reduction goal.

The Rapid Energy Policy Evaluation and Analysis Toolkit Project, known as the REPEAT Project, in August estimated current policy would reduce carbon emissions by 42% by 2030. The researchers now expect the next stage of the energy transformation will be slower to start, partly because of supply chain limits.

The average annual rate of solar photovoltaic additions jumps from 19 GW in 2021 to an average rate of 44 GW to 51 GW a year from 2023 to 2030, according to the group’s modeling. Onshore wind additions climb to 39 GW to 43 GW annually through the rest of this decade, up from 15 GW in 2020, the researchers estimated.

Looking further ahead, solar PV grows by 123 GW to 167 GW a year on average in the first five years of the next decade and wind increases by 26 GW to 41 GW a year on average in that period, the modeling found.

However, the rate of transmission capacity additions must accelerate by 50% from recent levels to meet those growth projections, and would have to double to meet a net-zero target for 2035, according to the report.

“Current U.S. transmission planning, siting, permitting and cost allocation practices can all potentially impede the real-world pace of transmission expansion,” the researchers said in the report.

Failing to accelerate transmission expansion beyond the recent pace of about 1% a year could forfeit about half of the emissions reductions that might otherwise be achieved under current policies, the researchers said.

According to the REPEAT Project’s modeling, about three-quarters of electricity comes from low-carbon sources in 2030 and about 90% in 2035 under current policies. If transmission expansion is limited, the share falls to about 61% in 2030 and 71% in 2035, the researchers said.

“If new transmission capacity cannot be added at a faster pace, growth of wind and solar power will be substantially constrained,” the researchers said. “The United States would thus be more reliant on coal and natural gas power plants to meet growing demand from electric vehicles and other electrification.”

Partly in response to the slow pace of regional transmission development, the Federal Energy Regulatory Commission last year proposed reforming its rules governing transmission planning and cost allocation as well as rules over interconnecting generators to the grid. It may take several years before any new rules are put into effect, however.

The REPEAT Project noted that its modeling indicates outcomes that would be expected from economic decision-making, but other factors can affect real-world results such as “the ability to site and permit projects at requisite pace and scale, expand electricity transmission and [carbon dioxide] transport and storage to accommodate new generating capacity, and hire and train the expanded energy workforce to build these projects.”

Energy efficiency will play a “crucial role" in decarbonizing the power system, even as lower-cost renewables make up a greater portion of U.S. generation and in scenarios where lower levels of building electrification keep electricity prices depressed, according to a report from the American Council for an Energy-Efficient Economy.

The U.S. currently generates about 20% of its electricity from renewable resources, and the U.S. Energy Information Administration expects that figure to double by 2050 even without additional policy support for wind and solar, said Mike Specian, a research manager within ACEEE’s state and utility policy program and lead author of the report.

“A major driver of that growth is cost,” he said in a June 21 webinar on the report's findings. “So that raises an important question .... what role, if any, should energy efficiency play in a high-renewable energy future?”

ACEEE examined five grid regions in the U.S. — California, Texas, the Pacific Northwest, the Southeast, and the Midwest — and concluded energy efficiency could reduce customer costs to the tune of $10 billion-$19 billion annually per region by 2050. Savings come from avoided energy use, generation capacity and transmission costs.

The research modeled the effect of 12 individual energy efficiency measures and packages and found that those affecting thermal space conditioning loads “are likely to have the greatest impact on both energy savings and avoided electricity system costs through 2050.” 

Modeled efficiency measures include building envelope improvements, a reduction in plug loads, and the use of more efficient heat pumps, water heaters and clothes dryers. 

There is variability among regions, however, and savings will be larger in regions “with lower baseline building energy codes, lower quality existing building stock, and more extreme temperatures, such as Texas and the Southeast," the report found.

However, the research shows consistently that energy efficiency “provides more value, the more quickly electricity generation decarbonizes,” said Specian. “It does this by offsetting the escalating costs of things like fossil-based energy and carbon capture under high renewable energy scenarios.”

The research also showed that, when considering a scenario where power sector emissions drop 95% below 2005 levels by 2050, commercial efficiency measures tend to deliver greater energy savings sooner, though they are ultimately surpassed by residential energy savings in most regions.

In every region ACEEE studied, commercial savings are greater than residential savings in 2030. And in all regions except California, residential savings are greater than commercial savings in 2050.

“This has to do with a number of factors including the rates of new building construction and the rates of building equipment replacement,” Specian said. “But what it shows is that there is more near-term savings potential in the commercial sector, and more long-term savings potential in the residential sector.”

For companies aiming to buy clean energy, the most effective and least expensive procurement strategy is “carbon matching,” according to a report by consulting firm Tabors Caramanis Rudkevich, or TCR.

With carbon matching, a company becomes carbon neutral by buying from anywhere more carbon-free electricity than they use in a year, according to TCR. The strategy is based on “locational marginal emission rates,” the amount of carbon emissions tied to specific nodes on the grid. Other approaches call for buying clean electricity to offset a company’s energy use without regard to the extent those purchases reduce overall emissions.

“If you want to do the best you can for the least money, then shift over and think about marginal emission rates as the metric to use,” said Richard Tabors, TCR president and one of the authors of the report.

Under the carbon matching approach, companies buy emissions-free power in areas with high carbon emissions from power plants, such as in the Southwest Power Pool and parts of the upper Midwest, without considering how close those sources are to where the electricity is being used, he said.

Sourcing renewable electricity from those areas will displace more carbon than, for example, purchases from California, which already has a high amount of emissions-free resources, he said.

The TCR study was supported by a grant from Meta Platforms, a leading clean energy corporate user. Meta is part of the Emissions First Partnership, which supports carbon matching. Companies in the group, launched in December, include Amazon, General Motors and Intel.

TCR assessed four clean energy procurement strategies, including the industry standard — annual energy matching under which a customer matches their load with clean energy on a yearly basis.

Besides carbon matching, the firm also considered local energy matching, where clean power is procured from the balancing area where it is used, and hourly energy matching, with clean electricity procurement lining up with the hour it is used from resources within the load’s balancing area. Google in 2020 set a goal of hourly energy matching.

The report looked at two load profiles: one representing stand-alone commercial retail buildings and the other representing data centers or industrial customers.

It studied those loads in five areas for geographic and regulatory diversity: the California Independent System Operator; the PJM Interconnection; Duke Energy Carolinas; Portland General Electric; and the Los Angeles Department of Water and Power.

“We found that carbon matching was the only annual matching strategy to consistently achieve carbon neutrality, regardless of customer load profile and location,” Tabors and the other authors said in the report.

The study found that local, hourly energy matching is the least efficient strategy for cutting carbon emissions. It fails to achieve carbon neutrality on an hourly basis and only achieves annual carbon neutrality, at a high cost, by buying more than twice as much electricity as needed, according to the report.

In PJM, it would cost a commercial retail company $113/MWh under an hourly energy matching strategy compared to $6.30/MWh under a carbon matching approach, the TCR analysts found.

Solar projects in the Electric Reliability Council of Texas footprint offer the lowest-cost clean energy projects and photovoltaic projects in southern SPP were the most cost-effective at displacing carbon emissions, according to the report. 

Corporate clean energy buying surges

The report comes amid a surge in corporate clean power procurement.

In the United States, 326 companies had contracted for 77.4 GW of clean energy as of the end of 2022, up from about 10 GW five years earlier, according to a report from the American Clean Power Association, known as ACP. The capacity includes about 45,050 MW of solar, 28,830 MW of land-based wind and 975 MW of battery storage.

The 36 GW of operating clean power for corporate buyers makes up 16% of all operating clean power in the U.S., according to the trade group.

The top 10 corporate clean energy purchasers account for 54% of all U.S. corporate procurements with 41.8 GW of contracted capacity, ACP said.

Carbon matching is part of an ongoing effort to expand options for companies that want to buy clean energy, according to Doug Miller, director of market and policy innovation for the Clean Energy Buyers Institute, or CEBI, until late last month.

“We don't necessarily need more wind in Texas or solar in California, so the idea is how do we be a bit more strategic with deploying energy so we actually shave off those locations and times that are not yet carbon-free,” he said.

Lifting procurement barriers

CEBI, affiliated with the Clean Energy Buyers Association, last year started the Next Generation Carbon-Free Electricity Procurement Initiative to develop a framework for new procurement options, including carbon matching.

“We want to see hourly solutions, we want to see carbon match solutions, we want to see solutions for small businesses,” Miller said. “We think you need an all the above approach in terms of what's available, and then let the market, let the customers decide which best matches what they want.”

In its procurement initiative, CEBI identified roadblocks to new clean energy procurement options, including a need for “energy attribute certificates” to contain more data on electricity sources, he said. Additional data on the certificates, such as hourly and sub-hourly time stamps and carbon intensity snapshots, would support new types of clean energy purchases, he said.

Locational marginal emission rates are not widely available, placing hurdles to the carbon matching approach, according to Tabors. PJM has published real-time locational marginal emission rates since late 2021 and ISO New England has started reporting marginal emission rates, he said.

The Federal Energy Regulatory Commission should direct grid operators to report the information in real-time, according to Tabors. The Infrastructure Investment and Jobs Act calls for the U.S. Energy Information Administration to report hourly locational marginal greenhouse gas emission rates, the report noted.

Despite White House and other efforts, new transmission projects to deliver the growing amounts of clean energy in the U.S. to where it’s most needed face what some observers call a permitting “Valley of Death.” But non-transmission solutions can fill the gap, stakeholders agree.

President Biden’s policies and executive orders have initiated many new transmission approval strategies, but permitting remains “the poster child for how things can get held up,” Senior Advisor to the President for Clean Energy Innovation and Implementation John Podesta told a May 23 CleanPower 2023 conference audience.

Policy and regulatory agencies have “many ways to say no” to new development, leaving the potential for streamlined transmission expansion in serious doubt, BloombergNEF Head of Research, North America, Tom Rowlands-Rees told Utility Dive.

Even with historic Inflation Reduction Act funding, U.S. power suppliers “cannot deliver the energy transition” if it continues to take 10 years to permit and build the needed transmission, Berkshire Hathaway Energy Renewables President and CEO Alicia Knapp told the same Cleanpower audience.

But new technologies and materials and new ways to use renewables, batteries and distributed energy resources can get more from existing transmission, analysts, utilities and other stakeholders said. They cannot defer the need for new transmission indefinitely, but the urgency to reduce customer costs and meet clean energy goals mean the time for them has come, they agreed.  

The transmission deficit

Through 2022, 1,350 GW of generator capacity and 680 GW of storage were actively seeking interconnection to the transmission system, an April Lawrence Berkeley National Laboratory study reported.

Market congestion costs from insufficient transmission were an estimated $13.4 billion for ratepayers in 2022 and are expected to grow, a March Grid Strategies paper calculated. And much of the U.S. faces an elevated risk of energy shortfalls from extreme heat-induced demand spikes, added the May 17 North American Electric Reliability Corporation 2023 Summer Reliability Assessment.

In response, Biden administration initiatives will prioritize interconnection queue, permitting and cost allocation reforms to expedite transmission deployment, the White House announced May 10. There will also be new emphasis on the economic, reliability and climate benefits of new transmission corridors, inter-regional transmission, grid-enhancing technologies and line upgrades, it added.

The interconnection queues are not the whole story, said New York Independent System Operator Vice President of External Affairs Kevin Lanahan. New York’s “class-year” approach, which identifies the most substantial project proposals, accelerated approval of 27 generation projects totaling 7,452 MW in 2021, and more than 90 class-year generation projects are being studied, he said.

New Southwest Power Pool, or SPP, queue management practices initiated in January 2022 put it on track to eliminate its queue backlog by the end of 2024, added SPP Director, Grid Asset Utilization, Casey Cathey. A consolidated planning process that “merges and optimizes queue requests with regional long-term planning” can eliminate organizational silos, he said.

“There can be no transition without transmission,” but “there are still issue like land permitting outside of SPP’s control,” Cathey added.

“Too many jurisdictions have authority to stop new transmission development,” agreed Dynamic Grid CEO Kay Aikin. Other options can, however, begin increasing the power system’s capacity to meet policy goals, she added.

As battery storage costs continue to fall, it has emerged as a non-transmission solution, though opponents insist it must be located precisely to be cost-effective.  

Storage-as-transmission

In 2019, SPP studies of its first storage-as-transmission proposals showed it was a viable alternative to new transmission builds or upgrades but was not cost competitive because batteries were too expensive at the time, SPP’s Cathey said.

Even then, batteries strategically placed at congested nodes where load profiles of limited capacity lines allow energy to be stored when loads ease to offset later demand spikes could defer new transmission builds, Cathey said. SPP’s storage-as-transmission tariff was approved May 26, and costs are now or will soon be low enough to make properly located storage a viable least-cost option to transmission line upgrades, he added. 

National Grid’s $50 million, 8-hour, 48-MWh battery which deferred an estimated $250 million transmission line for Nantucket Island is an example of the right kind of use case, said National Grid Clean Energy Development Director Terron Hill. It remains the largest storage-as-transmission project in New England, he added.

Regulators, utilities and system operators must use planning criteria that value optimizing existing transmission with storage, said Long Duration Energy Storage Council CEO Julia Souder. That will require “recognizing that battery project costs might be offset by the ratepayer benefits of reduced [renewable energy] curtailment and deferred capital expenditures for transmission,” she added.

Independent storage providers are concerned about owners of storage-as-transmission assets bidding into energy markets, said Jason Burwen, vice president of policy and strategy at merchant battery provider GridStor. “Owners of storage-as-transmission receive cost recovery through rates and should not compete in markets,” he added.

The locational and regulatory limits on storage-as-transmission make new grid-enhancing technologies, or GETs, and advanced wires materials, which are easier and faster to deploy, the smarter near term choice as a non-transmission upgrade, their advocates insisted.

Grid-enhancing technologies

The most often-used GET, Dynamic Line Ratings, or DLR, can expand a transmission line’s carrying capacity in real time based on readings from sensors throughout the system. Advanced Power Flow Control moves electricity away from overloaded lines to streamline energy delivery. And Topology Optimization uses multi-factor awareness to maximize a system’s carrying capacity.

National Grid’s upstate New York DLR deployment and its study of other GETs show they can begin to cost-effectively optimize today’s aging transmission system for a renewable energy future, said National Grid’s Hill. With engineering and deployment expenditures, DLR may cost $100,000 per mile, while new overhead transmission’s per mile costs in the Northeast are from $3 million to $6 million, he added.

Despite efforts at policy reforms, permitting remains the transmission project “Valley of Death” for Los Angeles Department of Water and Power, said its Power Engineer Manager Denis Obiang.

Where building new lines is impeded, LADWP is exploring “reconductoring,” which is replacing traditional line materials with advanced conductor materials, but is not one of the commonly identified GETs, Obiang said. “At a slight increase in cost over traditional steel, the new materials can increase performance 10%,” which is the highest capacity increase of any non-transmission alternative, he added.

But unlike reconductoring, GETs are the quickly deployable “low hanging fruit” for improving existing lines, Obiang added. “For a struggling load dispatcher, bringing marginally more power onto the system in a high demand hour can make a real difference,” he said.

Power provider EDF Renewables North America has helped finance new transmission capacity, its Vice President of Transmission Analytics, Rodica Donaldson said. But EDF has found GETs can be brought online in 16 months to 24 months with a cost in the tens of millions of dollars to defer transmission builds that could take years and billions of dollars, she added.

The data on congestion reduction with GETs are changing the historically conservative mindset of transmission owners, Donaldson said.

“Batteries help resolve the time dimension of congestion by shifting when energy is used, but GETs help resolve congestion’s distance dimension by optimizing the system-wide use of existing wires,” said Hudson Gilmer, CEO of DLR provider LineVision.

GETs can reduce the amount and cost of needed U.S. transmission, reduce some highly congested locations by 40% or more, and relieve the financial risks of transmission expansion, the Department of Energy’s draft “Transmission Needs” study reported in February. And they can potentially double system renewables capacity with a six month payback, an April Brattle Group study found.

It “intuitively makes sense to turn to easier-to-deploy, least cost technologies, but they require utility resources and studies,” SPP’s Cathey cautioned. And “not all transmission owners have an appetite for what they perceive as new technology risks,” he added.

“The industry has a reputation of being slow to adopt new technology,” Gilmer responded. “But many electric utilities are starting to see GETs near-term viability as new transportation and building electrification loads increase the need to protect their systems,” he added.

Duquesne Light’s Pittsburgh region DLR deployment is expected to increase transmission system capacity by an average of 25%, the utility reported in September 2022. It is now studying power flow control and sees topology optimization as “the end goal,” Duquesne Light Director, Advanced Grid Systems and Grid Modernization Elizabeth Cook said.

But deploying new technologies “is a business decision” guided “by regulatory mandates and by the utility business model,” Cook acknowledged. Use of GETs and advanced conductors may be limited by perceived risk as opposed to guaranteed returns through rates with traditional capital expenditures, she added.

Overbuilding strategically located utility-scale generation and batteries might be a more appealing near-term solution for regulated transmission owning utilities, some analysts said. 

Economic overbuilding

Building more solar, wind and batteries adjacent to existing transmission and load “is not a silver bullet for the queue problem but a way around it,” suggested Meredith Fowlie, professor of economics and faculty director for the Energy Institute at Haas, University of California, Berkeley.

“If transmission bottlenecks remain formidable, and if the costs of renewables and storage keep falling, overbuilding might be more economic than dealing with queue and permitting obstacles,” Fowlie said. “Instead of building where solar or wind are most productive, building where they can interconnect without additional costs or local objections might be adequate to reduce the need for new transmission,” she added.

Developers are already taking advantage of slightly less ideal renewable resource locations near load and existing transmission, “not because of policy but because of economics,” said SPP’s Cathey. They have realized they can optimize for conditions, costs and the opportunity to address congestion in SPP’s East rather than adding renewables to its backlogged Western queues, he added.

A fourth, and undervalued, non-transmission option is customer-owned distributed energy resources, which can cost-effectively meet demand at the local level, advocates said.  

Engaging customers

Engaging customers’ resources is becoming more urgent as loads from transportation and building electrification accelerate, DER advocates said.

Distribution system load flexibility can be a solution to transmission constraints that limit supply by flattening customers’ peak demand during the 5% to 10% of system hours that cause reliability threats, said Astrid Atkinson, CEO and co-founder of software provider Camus Energy. FERC Order 2222 recognizes enabling DER in wholesale markets can be a powerful tool in deferring the need for new transmission, she added.

But regulators must recognize and compensate customers for their resources’ value as energy, capacity, ancillary services and resource adequacy, Atkinson added.

Because of regulators’ resistance to doing that, “it is not possible right now to know how big a role DER can play” in reducing the need for new transmission, the LDES Council’s Souder added.

“DER plays a role, but it does not significantly change transmission needs because the localized transportation and building electrification load growth will be larger than the local DER can meet,” said LADWP’s Obiang. “It will take a comprehensive approach that includes all available options,” he added.

Rethinking transmission

There is no ideal non-transmission alternative to address the challenges facing new transmission development, analysts agreed.

But consideration of the roles of storage-as-transmission, GETs, overbuilding and DER “might force a redesign of the [planning and interconnection] process from the ground up to include modeling that recognizes constraints on building new transmission,” Haas economist Fowlie said.

Many utilities see GETs and other alternatives as a threat to reliability, “like rebuilding the airplane engine while flying it,” said Duquesne Light’s Cook. But non-transmission alternatives “allow rethinking transmission planning with coordination of all options that can defer the need for the many years it will take to bring new transmission online,” she added.

Regional studies of the right subset of technologies could lead policymakers to “a national optimization” of the transmission and distribution systems and the role of all the potential strategies to strengthen them, Dynamic Grid’s Aikin agreed. It should begin with increased use of DER flexibility “to take the burden off transmission,” and then use strategic overbuilding of renewables and storage, and deployment of GETs and reconductoring “until new transmission can be built,” she said.

No non-transmission solution can eliminate the need to expand and renew today’s 100-year old transmission system, added EDF’s Donaldson. “But policymakers and stakeholders need to act proactively to support deployment of alternatives to encourage companies like EDF to keep investing in clean energy development to meet U.S. climate goals,” she warned.

The U.S. Department of Energy on March 21 issued reports charting pathways to commercialize long-duration storage, advanced nuclear reactors and clean hydrogen.

The Pathways to Commercial Liftoff reports are designed to help industry, investors and stakeholders make decisions about the emerging technologies that are needed to slash greenhouse gas emissions from the power sector, according to DOE. They highlight possible solutions to the challenges facing the technologies and routes to commercialization.

“As we combat the climate crisis and race toward an equitable clean energy future, public and private partnerships will be more important and critical than ever before,” DOE Secretary Jennifer Granholm said in a statement.

About $260 billion needs to be spent for the rest of this decade to help commercialize the clean hydrogen, nuclear and long-duration energy storage sectors, according to DOE.

The U.S. grid may need 225 GW to 460 GW of long-duration storage to support power markets for a net zero economy by 2060, representing $330 billion in capital spending, according to the storage report. DOE defines long-duration storage as resources that can provide continuous energy for 10 hours to about 160 hours.

To reach commercial viability, inter-day storage technology costs must fall from $1,100/kW-$1,400/kW to $650/kW by 2030 and improve round trip efficiency, or RTE, from the 69% seen in best-in-class technologies in 2022 to about 75%, according to the report. Costs for multi-day technologies must drop from $1,900/kW-$2,500/kW and 45% RTE to $1,100/kW and 55%-60% RTE by 2030, DOE said.

“Market and regulatory mechanisms would need to evolve if [long-duration storage] economics are to be supported; priority interventions are needed to increase market certainty and improve risk-adjusted returns,” DOE said.

U.S. nuclear capacity could triple by 2050 from about 100 GW today, according to the report on advanced nuclear technology.

Power system decarbonization modeling indicates the U.S. will need about 550 GW to 770 GW of new emissions-free, firm capacity to reach net-zero carbon emissions, and nuclear power is one of the few proven options at that scale, DOE said.

The estimated “first of a kind” cost of a well-executed nuclear project is about $6,200/kW, but recent nuclear projects in the U.S. have had overnight capital costs of more than $10,000/kW, according to the report. 

Delivering first of a kind projects without cost overruns would require extensive upfront planning to incorporate the lessons from recent projects, DOE said, noting that subsequent projects would cost about $3,600/kW after 10 to 20 deployments.

“However, the nuclear industry today is at a commercial stalemate between potential customers and investments in the nuclear industrial base needed for deployment — putting decarbonization goals at risk,” DOE said.

Utilities and other potential customers see a need for nuclear power, but perceived risks of cost overruns and project abandonment have limited orders for new reactors, according to the department.

Clean hydrogen production for U.S. demand could grow from about 1 million metric tons a year to about 10 MMT/year in 2030, according to the hydrogen report. The sector needs $85 billion to $215 billion in investments for the rest of this decade, DOE said.

Up to 200 GW of new renewable energy sources would be needed by 2030 if water electrolysis is the predominant way of making hydrogen, DOE said.

The report calls for developing regulations for the sector, including methods of lifecycle emissions analysis across feedstocks and production pathways.

“These policy and regulatory developments, along with many others (e.g., changes that would streamline project permitting/siting), would take place across both federal and state agencies and would provide critical certainty to accelerate private investment,” DOE said.

New public and private funding and expected strong federal power plant emissions reduction standards have accelerated electricity sector investments in carbon capture, utilization and storage,’ or CCUS, projects but some worry it is good money thrown after bad.

CCUS separates carbon from a fossil fuel-burning power plant’s exhaust for geologic storage or for use in industrial and other applications, according to the Department of Energy. Fossil fuel industry giants like Calpine and Chevron are looking to take advantage of new federal tax credits and grant funding for CCUS to manage potentially high costs in meeting power plant performance requirements, including new rules, expected from EPA soon, on reducing greenhouse gas emissions from existing power plants.

Power companies have “ambitious plans” to add CCUS to power plants, estimated to cause 25% of U.S. CO2 emissions, and the power sector “needs CCUS in its toolkit,” said DOE Office of Fossil Energy and Carbon Management Assistant Secretary Brad Crabtree. Successful pilots and demonstrations “will add to investor confidence and lead to more deployment” to provide dispatchable clean energy for power system reliability after 2030,| he added.

But environmentalists and others insist potentially cost-prohibitive CCUS infrastructure must still prove itself effective under rigorous and transparent federal oversight.

“The vast majority of long-term U.S. power sector needs can be met without fossil generation and there are better options being deployed and in development,” Sierra Club Senior Advisor, Strategic Research and Development, Jeremy Fisher said. CCUS “may be needed, but without better guardrails, power sector abuses of federal funding could lead to increased emissions and stranded fossil assets,” he added.

New DOE CCUS project grants, an increased $85 per metric ton, or tonne, federal 45Q tax credit, and the forthcoming EPA power plant carbon rules, will do for CCUS what similar policies did for renewables, advocates and opponents agreed. But controversial past CCUS performance and tax credit abuses must be avoided with transparent reporting requirements for CO2 capture, opponents added.

New funding, new life

Federal spending authorized by 2021’s Infrastructure Investment and Jobs Act and the 45Q tax credit increase in 2022’s Inflation Reduction Act will make 2023 “a milestone year” for CCUS, moving it “from niche concept to mainstream investment,” and increase global CCUS capacity more than “sevenfold” by 2033, according to a March 2023 report by consultant Wood Mackenzie.

Tax credit support is a key reason many companies are investing in CCUS, Bloomberg News reported in January. Energy companies, like Competitive Power Ventures and Calpine, frankly acknowledged policy support as a key driver in recent CCUS proposal announcements.

The new public and private investment will allow power plants with CCUS to have a small positive or at least no more than a small negative financial return, said Clean Air Task Force Technology and Markets Director John Thompson. That may make CCUS a more cost-effective way to meet expected stricter pollution and emissions standards, he added.

DOE’s recent $2.5 billion offering for CCUS pilot and demonstration projects may be “an important opportunity for CCUS developers,” said Pamela T. Wu, a partner at the law firm Morgan Lewis. “It will identify which technologies are reaching implementation readiness levels to complement the continuing rapid deployment of renewables,” she added.

CCUS advocates agreed.

The point of CCUS support

“The point of the new federal investments is to support enough deployment to firmly establish the technology” and contradict some of the “misunderstandings” about past CCUS demonstrations, DOE’s Crabtree said.

Public debate consistently associates CCUS with enhanced oil recovery, which injects captured CO2 into aging oil wells to increase production, and “that is a misrepresentation,” Crabtree said. Congress set the enhanced oil recovery tax credit “at only $60 per tonne because producing oil earns revenue and because enhanced oil recovery limits the net climate benefit of CCUS,” he said.

CCUS opponents also argue the 2009 congressionally authorized grants for commercial-scale CCUS demonstrations at Boundary Dam, Petra Nova, and other coal plants underperformed, he added. But that should not stop DOE’s new efforts because “federal grants and tax credits supported solar and wind when early large-scale projects were expensive and performed hesitantly, and carbon capture is no different,” Crabtree said.

The new federal supports can make CCUS-equipped natural gas power plants valuable compliments to renewables and batteries in the U.S., added Carbon Capture Coalition Executive Director Jessie Stolark. And successful CCUS demonstrations at coal plants can allow U.S. technology “to help address Asia-Pacific region emissions where coal is still being used,” she added.

The history of past DOE-funded CCUS demonstrations, as detailed in the December 2021 Government Accountability Office report, “shows how to improve management and oversight,” Stolark wrote in January 2022. And the new federal tax credits and grants for power plant CCUS “go a long way toward providing federal policy parity” with clean energies, which was the “major barrier” to previous success, she added.

“The policy support for those big, complex, capital-intensive pioneer projects” was inadequate, Stolark said. “This time DOE made sure policy signals like the 45Q tax credit were in place before funding new demonstrations.” 

And “proof” that CCUS is now “a cost-effective technology for reducing emissions” is the Clean Air Task Force - documented 160-plus project announcements since the 45Q credit was increased, she added.

But some environmentalists and economists said their data proves the opposite.

Performance and underperformance

Pioneer power plant demonstrations, like NRG Energy’s Petra Nova and SaskPower’s Boundary Dam, left many doubts about CCUS performance, according to Sierra Club, the Institute for Energy Economics and Financial Analysis, or IEEFA, and others.

The increased energy needed to run the Boundary Dam coal plant CCUS retrofit, for example, reduced its output from 160 MW to 110 MW, “a 31% parasitic load,” said independent analyst Brendan Pierpont, a former Climate Policy Institute analyst. A 2021 analysis found the result was underperformance that reduced the system’s design for 90% CO2 capture to 65%, he added.

Data submitted to DOE on Enchant Energy’s proposed San Juan Generating Station coal plant CCUS retrofit estimated its pre-CCUS output of 847 MW will drop to 482 MW, “an over 40% parasitic load,” Pierpont said. That would lead to significant underperformance in capturing emissions because “40% of the fuel burned and 40% of the emissions would be just to power the CCUS,” he added.

Calpine’s commitments to the Sacramento Municipal Utility District, or SMUD, on the CCUS opportunity in retrofitting the utility’s 578 MW Sutter Energy Center natural power plant raised several performance concerns from the utility’s consumer advocacy group.

The plant can offer “much-needed“ system reliability by adding dispatchable low emissions generation as SMUD advances its high variable renewables, zero carbon by 2030 plan, but data to assess “the risk and liability” is needed, SMUD Rate Advisor Rick Codina wrote for SMUDWatch. The utility needs to answer questions about CO2 capture rates, about how to avoid potential long-term dependence on fossil fuel generation, and about how it will deal with natural gas price volatility and other uncertain operational costs, he added.

These examples reflect broader concerns of some with the economic viability of CCUS.

The levelized cost of electricity for power plants with CCUS is “at least 1.5 times to 2 times above current alternatives, which include renewable energy plus storage,” according to a March 30 IEEFA paper.

The only improvement in CCUS economics from past demonstrations “is that the federal tax credits and DOE grants are shifting part of the cost and risk to taxpayers,” said IEEFA Director of Resource Planning Analysis David Schlissel. DOE’s recent demonstration and pilot grants are “a good approach” because “they limit spending of taxpayer dollars until it is clear what works and what will be needed in 2040,” he added.

The 45Q tax credits help CCUS, but “the IRA’s overall provisions still make retiring coal plants and building renewables the economic choice,” agreed Rhodium Group Energy and Climate Practice Associate Director Ben King. Some CCUS will be built, and “if the DOE pilot and demonstration projects’ performance drives down cost and builds market confidence, there could be more,” he said.

Independent analyst Pierpont is more skeptical. The tax credit and DOE grants “could overcome some technical and operational issues,” but the performance questions “are fundamental to CCUS’s long-term financial viability,” and if politics undermine federal supports, CCUS investments “could become stranded assets with many years of amortized costs embedded in customer rates,” he added.

Clean firm dispatchable power will have higher value after 2030, but CCUS will have competition from other clean energy technologies, and CCUS may not be clean if better oversight does not produce accountability, Pierpont said.

The need for oversight and accountability for CCUS pilots and demonstrations is not in dispute, but how to get it is, Pierpoint and Sierra Club’s Fisher said.

Transparency and guardrails

CCUS advocates said oversight is built into the new federal initiatives.

“If performance is not verified, plant owners do not receive the $85 per tonne [tax credit] that makes projects financially viable,” said the Clean Air Task Force’s Thompson. “That is an incentive to plant owners to achieve the highest possible levels of performance,” he added.

But the tax code’s section 45Q “does not specify when and how taxpayers must demonstrate” they have met the 75% of baseline emissions “capture design capacity requirement,” Calpine’s December 2022 Treasury Department filing said. IRS guidance is needed “that furthers Congressional purposes,” it added.

Transparency is vital because the 45Q credit, which “should be an incentive to maximize CO2 capture,” can be used by developers instead “to maximize their return” without fulfilling the congressional intent to maximize emissions reductions, Sierra Club’s Fisher said. “That can be prevented by strong guardrails on the tax credit’s use and transparent data on captured and stored CO2,” he said.

Some fossil fuel plants currently do not run more than 50% of the time because they cannot compete in energy markets with low-cost renewables, Fisher said. As detailed in Sierra Club’s December 2022 Treasury filing, a small CCUS retrofit may meet the IRS’s 75% minimum capture requirement of those historically small baselines while reducing a retrofit’s capital cost, he added.

Revenue from the $85 per tonne tax credit would then make those plants’ production more cost-effective than not operating, Fisher said. But 75% of their 50% baselines means only 38% of emissions would be captured, uncaptured emissions would increase, and plant owners would earn 45Q revenue while minimizing capital costs for CCUS infrastructure, he concluded.

Treasury can address this by requiring “a rigorous recalculation of a plant’s baseline for any changes, including CCUS retrofits, to ensure they maximize carbon captured,” Fisher said. It should also require “transparently verified reporting of emissions captured throughout the CO2 chain, at the point of combustion, in the tower, and in transport and sequestration,” he added.

That will require due diligence by the IRS to protect taxpayers against unjustified claims for 45Q credits, he said. An April 2020 Treasury Department report showed that due diligence is necessary because 87% of 45Q tax credit claims between 2010 and 2019, totaling almost $894 million, did not meet EPA requirements for monitoring, verification and reporting, he said.

Transparency has been limited by IRS confidentiality requirements, but new efforts by the EPA may improve that, DOE’s Crabtree said.

“EPA can require better and more transparent auditing and recordkeeping,” Fisher said. “Transparency and accountability” are vital to “the integrity of the 45Q tax credit,” the Carbon Capture Coalition’s April 2023 Federal Policy Blueprint agreed. Calpine’s Treasury filing called for reassessing a plant’s baseline following any “major modification.”

Power plant 45Q tax credit claims must include “an EPA-approved Monitoring, Reporting and Verification plan” and make data publicly available, according to agency spokesperson Shayla R. Powell. But current reporting rules do not require data on CO2 beyond the power plant, and an EPA rulemaking begun in June 2022 focuses on CO2 for enhanced oil recovery and in industry, but not at power plants. 

For power plants, EPA must provide “rigorous accounting” and enforcement “from the point of capture to the point of permanent storage,” an April 2023 Natural Resources Defense Council brief responded, echoing Fisher.

With strong federal guardrails and oversight, CCUS could prove itself and find a role, some advocates and opponents said.

“The U.S. is spending a lot more on wind and solar subsidies” than for CCUS, said Rhodium’s King. And “the tax credit’s $85 per tonne is less than the EPA’s proposed $190 per tonne social cost of carbon, which means that with the right oversight and transparency, it may still prove to be an economic way to reduce emissions,” he added.

As California reels from the impact of high natural gas prices this winter – as well as the ripple effects on the electricity sector – some experts are urging policy-makers to focus on reducing the state’s dependence on natural gas in the first place. 
 
Natural gas prices have remained at higher than normal seasonal levels since late November and through the end of January, according to a report published by California Independent System Operator this month. As a result, CAISO electricity prices also increased, averaging more than $250/MWh in December – a fivefold increase since last year. 

In all, CAISO’s energy market saw additional wholesale costs of $3 billion in December, and $900 million for the first 25 days of January. 

Earlier this month, the California Public Utilities Commission held a meeting to discuss the high natural gas prices, their impacts on electricity markets, and hear from experts on ways to address them. 

The very first “is reducing our reliance on natural gas in California and advancing those policies that would support California’s [greenhouse gas] emissions goals, especially around building and transportation electrification,” William Walsh, vice president of energy procurement and management at Southern California Edison, told regulators at the meeting.

In addition, industry experts also stressed the need to ensure customers have information about these kinds of events, as well as look at ways to bolster demand-side load management on both the electric and gas side. 

Complex interactions between gas and electricity uses

At the height of the gas price spike in December, the commodity natural gas price in Southern California was almost eight times as much as the average price the previous December, as well as higher than the rest of the country. As a result, ratepayers in California have been experiencing severe sticker shock, CPUC President Alice Reynolds noted at the meeting – average residential gas bills in Southern California increased two to two-and-a-half times what they were compared to the same time last year.

“We need to be mindful that we’re undertaking a really monumental transition in California to decarbonize our economy right now, which means transitioning away from our dependence on gas. There are a lot of complex interactions here between gas and electricity uses, and the impacts to customers’ bills – and we need to be considering the big picture when we think about mitigation strategies,” she said.

Earlier this month, the CPUC moved to accelerate the climate credit, that California ratepayers normally receive in April, to lower customer bills. The credit ranges from $90 to $120, according to the CPUC. Simultaneously, California Gov. Gavin Newsom, D, is urging the federal government to investigate the natural gas price spike, and take a closer look at whether it is the result of market manipulation, anti-competitive behavior, “or other anomalous activities.”

Gas prices in the West touched their highest annual point in the second half of December and began to subside in January, although still at a relatively high level. CAISO pointed to several reasons for that in its recent report: colder than usual temperatures in the West and Canada pushed up gas demand; there were lower gas storage inventories than usual – in part because of the higher gas usage during the heatwave California experienced last summer; as well as California’s lack of local gas supply and position at the end of the interstate pipeline system. 

In addition, pipeline maintenance work in West Texas reduced the amount of natural gas flowing west and raised gas prices in Southern California, the U.S. Energy Information Administration said in a January report.  

Panelists at the CPUC meeting pointed to other reasons for the high gas prices. For instance, the prolonged drought in California has drastically reduced hydroelectric generation output in the market as compared to last year, Gillian Clegg, Pacific Gas & Electric’s vice president of energy policy and procurement, said. 

“What that has meant is that that electricity has to be replaced – and it’s been replaced by gas-fired generation, increasing the demand for gas being used for electric generation,” she said. 

Impacts on electric costs

The impacts on the electricity market have been significant. California’s electricity markets are heavily interdependent on the gas market, and its natural gas generators  provide about half of its electricity generation. It’s still common for natural gas generators to be the marginal resource in the electric market, according to Molly Sterkel, a program manager with the CPUC’s energy division. 

“What that means is that the natural gas generators frequently act as price setters – electricity prices are commonly just a simple multiplication of the average heat rate of gas plants at the time and the price of natural gas,” she said.

December was the single highest month of wholesale electric costs that California has seen in the last five years, according to Sterkel. It’s unclear, however, how the wholesale costs will flow through to customers, since different market participants – including the investor-owned utilities and community choice aggregators – have different hedging strategies for their electricity portfolios, she said.

Since power markets are most of the time price-takers, policy-makers need to be cognizant that while electricity prices are regional, gas prices are national, continental and increasingly prone to global market forces because of the rapid increase in liquefied natural gas exports, said Fred Heutte, senior policy associate with the NW Energy Coalition. 

More broadly, the Western region finds itself in a situation where it has fewer electricity supply sources to switch to when gas costs rise, said Becky Robinson, a principal economist with CAISO. Ordinarily, if a resource becomes less economic in the electricity markets, other resources would be dispatched instead. But with factors like the continued retirement of coal plants across the West, “there’s just a little less switching available for the market to do.”

“This underscores the inter-relatedness of the gas markets and the electricity market and I think in terms of some of the potential… things to consider going forward, thinking about coordinated planning between and across the gas and electricity space could be very important…” she said. 

Possible solutions

California faced similar issues during the electricity crisis of 2000 and 2001, Eric Gimon, senior fellow with Energy Innovation, told Utility Dive. At that time, demand for gas increased because the hydropower sector was producing a lot less energy, leading the price of gas to shoot up.

There are different ways policy-makers can protect against these price spikes and prevent electricity from becoming so unaffordable.

“First of all, you want people to be on long-term locked-in [power] contracts,” Gimon said. One advantage that California’s power sector has is that renewables tend to be on long-term contracts, meaning their prices are locked in at the time the contract was signed and a lot of the grid’s supply is not affected by these prices. 

The cheapest and best way for regulators to mitigate the impacts of high natural gas prices, however, is improving electric and gas demand flexibility, said Gimon. 

“And because California is trying to decarbonize, we’re trying to reduce our exposure to gas – so if we accelerate some of these programs, we’ll reduce exposure to gas prices,” he said. 

Demand-side management is one of the best short-term policies that policymakers and consumers have at their fingertips to mitigate the impact of gas and electricity price swings, according to Brian Turner, policy director, Western states, with Advanced Energy United. This can include adjusting electricity use through consumer behavior, but also using advanced energy devices. 

“Much of the new advanced energy devices that exist and are coming on the market allow consumers to do that without having to think too much about it – they can set it and forget it,” he said. 

And a potential long-term play is getting California off dependence on volatile gas prices by adding more clean resources, like renewables, clean firm resources, and battery storage, said Turner. 

As energy officials in California conduct their long-term power planning, “they need to update their projections of gas prices so that that volatility is reflected… so as you’re making a long-term resource decision, the volatile, risky gas investments are less attractive…” he said.

Heutte agreed at the CPUC meeting that the root cause of the issue is not the markets, but overdependence on natural gas.

“We have a double-binded scarcity pricing [issue] in both the gas and power markets but because power is a gas price taker, it puts us in a very tight spot during these market price spikes,” he said.

A high priority for the NW Energy Coalition is providing customers with information during price spikes like these, and regulators should also look at reforming hedging and fuel cost adjustment policies and dramatically accelerate electricity and gas demand-side load management, he said.

In addition, the state needs to look at supply alternatives and reserves, and “extending the dependence on gas for reserves on the power side is really not going to be the answer,” Heutte said. Instead, the state can look at adding more batteries, using hydro storage that’s available, and in the longer term, enlisting load and resource diversity across the widest Western footprint possible. 

As California seeks to do this, conversations around better connecting the broader Western grid will become especially important, according to Sarah Steinberg, director at Advanced Energy United.

That includes better transmission as well as “creating that market platform, where states can both be exporting and importing according to their needs and access clean energy wherever across the West it is being produced at any given time – so that reduces the need for these individual [gas] plants that set that high marginal cost,” she said. 

Nearly 30% of utilities responding to a survey said they have increased their carbon-free energy supply by 10 percentage points or more from 2018 to 2021, with most companies reporting they’ve expanded emissions reduction targets, according to a recent industry report.

The Smart Electric Power Alliance’s “2023 Utility Transformation Profile” said 66% of utilities that responded reported an increase in carbon-free retail supply since 2018. No change in carbon-free supply was reported by 19% of respondents and 18% said they’re supplying less carbon-free energy.

“The utility industry’s transition to carbon-free energy is uneven,” the report said.

SEPA said 63 utilities, representing about one-third of electric customers in 29 states, completed the survey. When including partially completed surveys, the number rose to 118, representing 51% of electric customers in 41 states. Most of the 118 utilities are investor-owned, with public power utilities and distribution cooperatives also participating.

Utilities have set different carbon-reduction targets that include net-zero, carbon-neutral, carbon-free, greenhouse gas-free and relative emissions reduction. The target type indicates what a utility will do to decarbonize. For example, a 100% renewable energy target does not include nuclear energy and a net-zero target will use offsetting, such as carbon sequestration or carbon credit trading, the report said.

The study said 62% of respondents have developed a publicly available action plan to support a carbon-reduction target and 65% have incorporated at least one interim target in their goals.

In addition, three-quarters of U.S. electric customer accounts are served by a utility with a 100% carbon reduction target or by a utility owned by a parent company that has set that target.

But just 59% of respondents have established a plan to facilitate electric vehicle deployment, according to the report. 

Utilities are assessing the impact of climate change on their operations, adapting to a changing climate to minimize harmful effects and developing climate-resilience strategies to specify investment needs, according to the study.

Many elements of the energy transition “put upward pressure on rates,” the report said. With sharply higher costs for energy, utilities can provide affordable energy by using a combination of short-term bill assistance and management programs that are offered by 87% of utilities participating in the survey, the report said.

In addition, 64% of utilities in the survey offer energy-efficiency programs.

To reach an “equitable, carbon-free energy system” utilities must assess and promote equity in planning for the transition. However, 58% of respondents said they have not assessed energy equity as part of generation, transmission or distribution planning.

Utilities also report interconnection and transmission bottlenecks on new renewable energy projects. As more renewable and storage systems are interconnected, the U.S. will need to double or triple transmission capacity to accommodate those resources and provide 100% clean electricity by 2035, the report said.

To help reach that goal, the Inflation Reduction Act will provide nearly $3 billion in federal funding for transmission projects.

Transportation Secretary Pete Buttigieg and Energy Secretary Jennifer Granholm stressed the importance of their agencies working together under a new national blueprint released Jan. 10 that aims to eliminate greenhouse gas emissions from the transportation sector by 2050. 

Buttigieg said during the Transportation Research Board’s, or TRB’s, annual meeting in Washington, D.C. on Wednesday the Biden administration is focused on working with states to build out a national EV charging network and ensuring such infrastructure is added in rural areas, at multifamily dwellings and low-income communities.

To accomplish this, the blueprint tries to meet people where they are: People tend to drive longer distances in rural areas, he said, stressing the potential gas savings, and they live in single-family housing, allowing them to charge at home. 

But to achieve those goals, the two agencies must work together.

“This blueprint allows for this kind of cooperation,” said Granholm. “Having one goal, driving towards that one goal, and bringing to bear the equities of each of our offices is just really important.”

A network that places chargers every 50 miles along interstate highways in a way that is tailored to each state and locality is “significant,” Granholm said. “All of this is being done in partnership and in collaboration, and that’s what the blueprint is all about.”

To decarbonize the transportation sector, the U.S. National Blueprint for Transportation Decarbonization aims to increase convenience and efficiency and transition to clean options. The strategy will focus on research and investment to support deployment before 2030, then shift to scaling up clean solutions deployment between 2030 and 2040 and complete the transition between 2040 and 2050. 

During the TRB meeting, Jennifer Homendy, chair of the National Transportation Safety Board, said she supports the transition to EVs but cautioned against advancing the technology too fast and stressed the importance of keeping Vision Zero goals at the forefront. She called out the heavy and fast-accelerating electric SUVs and pickup trucks being rolled out, including GMC’s new Hummer EV, which has a battery pack that weighs as much as a Honda Civic, raising the risk of killing or injuring pedestrians and other road users.

Granholm said the agency is working to lower the cost of producing batteries to help drive down the cost of buying an EV, noting that with tax credits, vehicles such as the Chevrolet Bolt are affordable to many Americans.

Due to growing demand and federal grants, 75 companies are opening in the U.S. that are working on various aspects of producing EV batteries, such as manufacturing the batteries, critical minerals processing, or being involved in some piece of the supply chain, Granholm said. Those jobs had previously been located in countries that are considered economic competitors. 

“It’s coming to the United States because of policy. Policy really does make a difference,” she said. 

Buttigieg said the transportation economy was moving towards EVs but not fast enough to meet U.S. energy goals. He added that the rollout needed to be equitable, which is why the federal investments in the bipartisan infrastructure law and the Inflation Reduction Act were needed.

Granholm said virtual power plants would help bring resiliency to the grid, while new transmission lines added through the infrastructure law will add greater capacity. Buttigieg said the infrastructure law is also helping transit agencies purchase electric vehicles. 

“We’re putting our money where our mouth is,” Buttigieg said. The infrastructure package “makes the biggest investment in public transit at the federal level in the history of U.S. transportation.”

He added, “Even if we weren’t aggressively trying to decarbonize the system of transportation, that alone is one of the biggest and best things we could do from a climate perspective.”