Duke Energy is already under fire in North Carolina for its plan to blow off a state deadline to curb carbon pollution while also building a massive new fleet of fossil fuel plants.

Now, the company’s blueprint is locked on a collision course with fresh rules from the Biden administration, which target coal and new natural gas plants and take effect in eight years.  

“Duke is going to have to go back to the drawing board,” said David Neal, senior attorney with the Southern Environmental Law Center, “and come up with an alternative that is compliant with the rules.” 

While much focus on the long-awaited Biden rules has centered on coal, their impact on natural gas is arguably more significant. Duke isn’t alone among American utilities in being forced to re-examine long-term generation plans as a result. 

“We think it’s important for every utility and every commission to take a step back,” said Amanda Levin, director of policy analysis with the Natural Resources Defense Council. 

But even as the federal regulations underscore a law unique to the state, it’s not clear if North Carolina regulators will take a beat – or even if there’s time for them to corral Duke and an array of stakeholders to rework, vet, and approve a new carbon reduction and long-range plan due by the end of the year. That’s why many advocates say debate over the utility’s immediate next steps will be crucial. 

“It’s going to be important to adopt a near-term action plan that really is ‘least regrets,’” said Neal, who’s representing numerous clean energy groups in the proceeding on Duke’s generation plans. “The new rules just put further emphasis on what we already knew was true: we’re going to have to accelerate the adoption of clean resources.”

‘Not… achievable on the timelines presented…’

Duke’s existing fleet of natural gas-fired plants aren’t affected by the new Biden rules. Nor are the smaller gas plants Duke proposes to occasionally satisfy peak demand and serve other limited roles on the electric grid.

But the company plans at least five large, combined-cycle plants in the Carolinas that are impacted by the rules. The four projected for North Carolina include a 1,360-megawatt plant in Roxboro, about an hour north of Durham, for which state regulators are now weighing a permit application.

Natural gas is a fossil fuel, but Duke deems the Roxboro plant and others like it essential to the zero-carbon electricity future that state law mandates by 2050. These baseload generators can back up sources like wind and solar to ensure reliability. At the point of combustion, they produce about half the carbon pollution of coal. And in theory, hydrogen molecules separated from chemical compounds could ultimately supplant gas as a fuel, bringing the plants’ carbon emissions down to almost nothing. 

“Natural gas is available 24/7 — with fewer emissions than coal and at a lower cost than renewables alone,” Duke said on its website this year, around the time it asked regulators for permission to build the Roxboro plant. “The new [Roxboro] units would be designed to operate on carbon-free hydrogen in the future.”

But critics say this rationale is flawed in virtually every respect. The cost of natural gas is on the rise, and one recent study showed it was a major driver of recent Duke rate hikes in parts of North Carolina. In December 2022 during Winter Storm Elliott, gas plants failed when they were needed most — in the wee, frigid hours before the sun rose — helping to cause rolling blackouts that impacted half a million customers in the state. Drilling and transporting gas leaks methane, a greenhouse gas 80 times more powerful than carbon, nearly canceling out reduced carbon pollution from smokestacks.

As for hydrogen, experts believe it can serve a small role in a zero-carbon economy — but mostly not in the power sector. Even if it’s carbon-free when burned, hydrogen made from fossil fuels is hardly nonpolluting and also inefficient. Hydrogen fuel produced from renewables should be reserved for limited applications, they say, such as long-distance aviation fuel or to power the few gas plants still running in the middle of the century. 

“In our modeling,” said Levin, “hydrogen in the power sector is used just for that last 5% of the decarbonization of the entire grid.” 

Still, the power plant rules promulgated by Biden’s Environmental Protection Agency don’t wrestle with reliability, ratepayer impacts or even methane leakage. They cover carbon dioxide pollution alone, and they’re designed to reduce what’s emitted from the smokestack by 90% beginning in 2032. 

That limit is based on carbon capture — in which carbon dioxide is sequestered underground rather than released into the atmosphere — a technology widely viewed as infeasible in North Carolina because of its geology. And while other techniques that would achieve the same pollution cuts are allowed under the federal rules, none are yet ripe. 

One candidate is now being developed at utility scale in Texas but won’t be deployed until at least three years from now. As for hydrogen, it would have to fuel 96% of Duke’s new baseload gas plants beginning in 2032 to meet the emissions limit — an impossible feat according to the company’s own communications with regulators.

Duke’s current forecast shows its gas fleet running on about 3% hydrogen beginning in 2041, then “holding steady until significantly more hydrogen is required to meet carbon-neutral by 2050,” to comply with state law. And in a brief discussion of the impending federal power plant rules in its August draft of its long-term plan, Duke noted: 

“Hydrogen is an important and potentially transformational fuel for the future of the resource portfolio, [but] the volumes necessary to utilize the hydrogen compliance pathway are not thought to be achievable on the timelines presented.” 

‘It’s a pretty huge gap’

Thus, if regulators allow Duke to build large new baseload gas plants, the company can only run them 40% of the time or less, beginning in 2032 and until technology becomes viable to slash their emissions.

The Roxboro plant, which Duke plans to put into service at the beginning of 2029, would operate at its planned capacity for just three years in that case. Afterwards, its vaunted ability to provide around-the-clock electricity would be severely curtailed. 

Multiply the Roxboro conundrum by five, and the mismatch between the Biden rules and Duke’s gas ambitions becomes clear. 

In its August discussion of the expected Biden rules, Duke said it considered running its new combined-cycle baseload plants at 50%. Making up for the resulting difference between demand and supply, including building another large gas plant that would run at half-speed, would require an extra $3.6 billion, the company estimated.

Tyler Norris, a former vice president at Cypress Creek Renewables and a PhD candidate at Duke University, estimates that if the 6,800 megawatts of baseload gas plants Duke announced in January were planned to run at 75% and had to ratchet down to 40% operations, the difference would be greater still. Filling it only with solar could require 9,500 megawatts of capacity in a single year — nearly double what’s online in Duke’s territory today. 

“That’s probably on the high end,” said Norris, but, “it’s a pretty huge gap. Something’s going to have to change in the plan.”

Then, there’s the question of whether it makes sense for ratepayers to pay to fill that gap, especially if they’re also shelling out full price for underutilized plants. 

“We’re all paying for these plants that admittedly have to sit idle more than half of the time?” asked Dave Rogers, deputy director for the Sierra Club’s Beyond Coal campaign. “Should customers really be forced to pay for those?”

Adhering to the Biden rules on coal plants appears more straightforward.  

Duke must shut down its entire coal fleet by the start of 2039, and any plants still running in 2032 must be fired partially with gas. The utility already plans to meet that deadline for eight of its 12 remaining coal smokestacks, covering six sites. Two outliers in Belews Creek, just outside Winston-Salem, can already be fueled with gas. That leaves two units in Roxboro, about an hour north of Durham, that the utility now plans to keep online until 2034.

“The logical thing is to retire that coal plant at least a couple of years earlier. Whatever replaces it will be lower cost,” said Rogers. “That’s the big thing in front of the commission as it pertains to the [coal plant] rules.”

Timing also looms large. State law requires Duke to curb carbon emissions 70% by 2030, with two years’ wiggle room. If regulators authorize a nuclear or wind project that causes logistical delays beyond Duke’s control, the postponement could be indefinite. The company now hopes to exploit the latter loophole, with its preferred path to net zero achieving the 70% benchmark by 2035 or even 2037. 

With their deadline of 2032, however, the Biden rules help bolster the case for Duke to rein in its carbon emissions sooner. Doing so wouldn’t just make it easier for the utility to meet the ultimate goal of near-zero emissions by midcentury. It would also significantly reduce overall carbon levels in the atmosphere. 

“The thing about climate is it’s not just about achieving net zero in one year and one year only,” said Levin. “Climate is a cumulative emissions problem. If you’re doing status quo until the year you’ve made a net zero commitment, you’re not consistent with a 1.5 or 2 degree warming trajectory.”

No change to the ‘path forward’? 

Still, while advocates have long pressed Duke to build more battery storage, solar, and wind in place of gas and coal, making the switch in the complex utility modeling tools is no simple task, with a host of variables involved — from transmission capacity to reliability to siting.  

“Duke has already submitted its modeling twice now. I doubt that either North or South Carolina commissions will want to do another round of that at this point,” said Maggie Shober, research director for the Southern Alliance for Clean Energy, on a recent webinar about the Biden rules. But, she added, “this will absolutely come up in the process before the [North Carolina Utilities] commission.”

For its part, Duke hasn’t indicated any plans to re-do its projections.  

“While we are analyzing the final rules, our view is that [they do] not change our path forward in North Carolina as we continue retiring our coal plants and supporting the state’s unprecedented growth with an all-of-the-above approach that’s designed to deliver affordability and reliability for customers,” company spokesperson Bill Norton said in an email. “Natural gas remains an essential resource in this diverse mix that can be dispatched to meet demand 24/7.”

If that position holds, and state regulators don’t seek to change it, it raises the stakes considerably for the “near-term action plan” expected as part of the plan due by the end of the year, as well as the permit application pending right now for the Roxboro plant.

That short-term plan, said advocates, shouldn’t just account for the risk of new gas resources and the timing of coal retirements, but also allow for more renewables by removing the annual connection caps Duke proposes for both battery and solar.

“I think this is an excellent opportunity,” said Norris, “to revisit the potential to achieve a higher interconnection rate for zero-carbon resources.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

Duke Energy said its goal is to ensure energy reliability for its customers as strong economic development successes and population growth power the Carolinas’ energy needs.

The Bad Creek pumped storage facility is located in Salem, S.C. It came online in 1991 and is the largest “battery” on the company’s system, according to a release. The units were upgraded in phases, adding 80 MW of capacity to each new pump turbine. Unit 2 was completed in 2020, Unit 1 was completed in 2021, Unit 3 was completed in 2023 and Unit 4 was completed in April 2024.

“This investment in Bad Creek demonstrates our commitment to improving reliability across the Carolinas. Pumped storage technology gives us operational flexibility, allowing us to store energy and then deploy that energy when customer demand is highest,” said Preston Gillespie, executive vice president and chief generation officer and enterprise operational excellence. “Expanding our energy storage capabilities is just one of the many steps we are taking in the next phase of our energy transition.”

Duke Energy is working to extend the Federal Energy Regulatory Commission operating license of the Bad Creek pumped hydro storage facility, which is set to expire in 2027.

In addition to this upgrade project, Duke Energy is evaluating the potential to add a second powerhouse at Bad Creek that would further help Duke Energy add capacity as well as address increasing system variability, from the growth of solar and customer usage, in a reliable and affordable way. If pursued, the second powerhouse could be in-service as earlier as 2034.

“From population growth to the expansion of manufacturing and other major economic development wins, the Carolinas are booming,” said Mike Callahan, Duke Energy’s South Carolina president. “We must have a diverse energy mix to account for this growth on the coldest winter nights and the warmest summer days. We continue to look at solutions like expanding Bad Creek to make sure the power is there when customers need it, and it is as affordable as possible – providing certainty as they go about their daily lives.”

Expanding operations at Bad Creek also provides significant economic benefits of $7.3 billion to South Carolina, as the state benefits from construction and general infrastructure activity, by 2033.

Duke Energy Carolinas, a subsidiary of Duke Energy, owns 20,700 MW of energy capacity, supplying electricity to 2.9 million residential, commercial and industrial customers across a 24,000-square-mile service area in North Carolina and South Carolina. Duke Energy is headquartered in Charlotte, N.C. The company’s electric utilities serve 8.4 million customers in North Carolina, South Carolina, Florida, Indiana, Ohio and Kentucky, and collectively own 54,800 MW of energy capacity.

Duke Energy is executing an ambitious clean energy transition, keeping reliability, affordability and accessibility at the forefront as the company works toward net-zero methane emissions from its natural gas business by 2030 and net-zero carbon emissions from electricity generation by 2050. The company is investing in major electric grid upgrades and cleaner generation, including expanded energy storage, renewables, natural gas and nuclear.

It’s part of a newly-filed update to Duke’s 2022 integrated resource plan as the utility aims to comply with North Carolina’s emission mandates. That 2021 law requires utilities to reduce carbon dioxide emissions by 70% by 2030, compared with 2005 levels. The law also calls for net-zero emissions by 2050.

In the updated filings, Duke offered three scenarios that would get the company to 70% by 2030, 2033 or 2035.

The utility prefers the 2035 timeline. By that year Duke is proposing to add 600 MW of capacity from two small modular reactor sites, with both sites being the same reactor technology.

“Advanced nuclear will provide significant operational flexibility that will be needed to support increased deployment of renewable energy resources,” said the utility in its latest filings.

In a timeline prepared in filings to regulators, the utility said it plans to choose an SMR technology for the Belews Creek site between 2023 and 2025. Duke plans to apply for an early site permit from the U.S. Nuclear Regulatory Commission (NRC) in mid-2025.

The projected in-service date for the Belews Creek SMR would be the first quarter of 2034, with the SMR at the second site coming online in the first quarter of 2035.

Duke plans to end coal-fired power generation at Belews Creek by 2036. The 2,200 MW, two-unit coal and natural gas plant is located on Belews Lake in Stokes County, North Carolina. In 2020 and 2021, natural gas was added to the station to allow up to 50% natural gas co-firing on both units.

Duke’s recommended 2035 portfolio also includes a “near-term action plan” that would build up additional solar and wind generation and provide more electricity storage in batteries by the early 2030s.

While Belews Creek would be retrofitted for new nuclear, Duke’s Roxboro and Marshall coal-fired plants would shift to natural gas. Duke says those combustion turbine plants would be able to blend hydrogen for electricity.

Duke Energy said it is also in the process of seeking 20-year license extensions for the 11 existing nuclear units operating at six plants in the Carolinas.

Duke Energy expects the deal involving the unregulated business to close by the end of 2023. The investor-owned utility expects net proceeds of approximately $1.1 billion from the transaction.

Duke began shopping its renewables business in Sept. 2022 as it sought to focus on the growth of its regulated businesses.

“As one of the country’s largest renewable energy operators, Brookfield has the resources to support the continued growth and success of the Commercial Renewables’ portfolio,” Duke Energy CEO Lynn Good said in a statement. “This sale is an important step in our transition into a purely regulated company with significant grid and clean energy investment plans that will deliver benefits to our customers and stakeholders.”

The sale agreement includes more than 3,400 MWac of utility-scale solar, wind, and battery storage across the U.S., net of joint venture partners ownership, in addition to operations, new project development, and current projects under construction.

The primary operations of Duke’s utility-scale renewables business will remain in Charlotte, N.C. and the Duke Energy employees that support the business will transition over to Brookfield to maintain business continuity for its operations and customers, the companies said.

The agreement between Duke and Brookfield is subject to regulator approval by the Federal Energy Regulatory Commission.

Duke said it is still moving forward with a separate sale for its distributed energy business, which the utility also intends to close by the end of the year.

A microgrid has been placed into service in the town of Hot Springs, North Carolina that will be able to power the entire town during an outage.

The Hot Springs microgrid consists of a 2 MW (AC) solar facility and a 4.4 MW/4.4 MWh lithium-based battery storage facility. While the battery only technically has a 1-hour duration, the town's typical load is typically less than 1 MW, potentially extending the battery's available duration to at least four hours.

In addition to providing clean and reliable energy for the town of Hot Springs, the microgrid will also perform grid services, such as frequency and voltage regulation, as well as ramping support and capacity during peaks on Duke Energy's system.

“Duke Energy has numerous smaller microgrids on our system, but this is our first microgrid that can power an entire small town if its main power line experiences an outage,” said Jason Handley, general manager of Duke Energy's Distributed Energy Group.

Hot Springs has a population of just over 500. The town has limited rerouting options in the event of an outage.

During its testing phase, Duke Energy’s microgrid was able to pick up the town’s entire load from a black start without any help from the energy grid – using only solar and battery storage to restore power. The microgrid served the town’s load while the company gathered data.

Duke Energy worked with the technology company Wärtsilä, which supplied the battery energy storage system for the project. The microgrid utilizes Wärtsilä’s energy management system, the GEMS Digital Energy Platform, for integrated control of both the solar and energy storage facilities.

Duke Energy has over 60 MW of microgrid capacity connected throughout its regulated areas.

In Asheville, North Carolina, Duke Energy operates a 9 MW lithium-ion battery system at a substation site in the Rock Hill community.

In Haywood County, North Carolina the company has a 3.8- kWh lithium iron phosphate battery and 10 kW solar DC microgrid installation serving a communications tower on Mount Sterling in the Smoky Mountains National Park. 

Duke Energy said it has completed a 700 MW solar project portfolio in Florida as part of its resource plan filed with regulators.

Completion of the 74.9 MW Charlie Creek Solar Power Plant in Hardee County marks the last of 10 solar projects in Duke's commitment with the Florida Public Service Commission to bring 700 MW of solar generation online from 2018 through 2022.

Melissa Seixas, Duke Energy Florida state president, said the utility plans to provide 1,500 MW of solar generation to residents and businesses by 2024, representing a $2 billion investment.

Duke set goals of net-zero methane emissions from its natural gas business and at least a 50% carbon reduction from electric power generation by 2030. The utility has a net-zero target of 2050.

Duke Energy recently completed the first of 10 community solar projects in Florida as part of a new program. Once completed, the Clean Energy Connection community solar program will feature 750 MW of generating capacity.

The Fort Green project was built on around 500 acres of former mining land. The project consists of nearly 265,000 solar panels, using a fixed-tilt racking system that will produce enough energy to power more than 23,000 average-sized homes at peak production.

In August, Duke Energy announced that two battery storage projects in Florida totaling 17.2 MWh of combined energy capacity were brought online in Alachua and Hamilton counties.

NOTE: Be sure to watch our POWERGEN+ network webinar: “How the fast-ramping SGT6-9000HL at Duke Energy’s Lincoln Station supports solar and the path to net-zero.”

Duke Energy’s Lincoln Combustion Turbine Station is now certified with the Guinness World Records title for the “most powerful simple-cycle gas power plant.”

The plant, powered by a Siemens Energy SGT6-9000HL turbine, achieved an output of 410.9 MW during testing on Jan. 30.

Siemens Energy is currently testing the 60Hz SGT6-9000HL turbine at the Lincoln site, located near Denver, North Carolina. In April 2020, the company synched the unit to the grid for the first time.

Siemens Energy plans to turn the unit over to Duke Energy in 2024. It would become the most efficient simple-cycle combustion turbine in the utility’s fleet and 34% more efficient than the other turbines at the Lincoln site.

The SGT6-9000HL is based on four generations of technologies and five previous models, starting with the SGT-2000E in the 1980s. It is designed to run longer between maintenance cycles.

The HL-class’s engine architecture is composed of an air-cooled four-stage power turbine, hydraulic clearance optimization for higher efficiency at full load while facilitating immediate restart, a steel rotor design with Hirth serrations and a central single tie rod and a “can annular” combustion system, according to Siemens Energy.

The advanced can-annular combustion system with dual fuel capability allows for higher firing temperatures and more operational flexibility. Twenty-five premix burners improve the fuel/oxygen mixing, and the ACE combustion system allows for GT turn-down to 30 percent GT load.

The turbine has fast-responding capabilities, with a ramp up and down rate of about 85 MW per minute. This is an important quality when integrating with renewables.

Duke Energy started construction on its Lincoln expansion project in September 2018. The 16-unit power plant was selected because its 746-acre site allowed room for expansion.

Duke Energy announced the completion of two battery storage projects in Florida totaling 17.2 MWh of combined energy capacity.

The recently completed Micanopy battery site in Alachua County is 8.25 MW/11.7 MWh and is located 15 miles southwest of Gainesville. The site provides a cost-effective solution for focused power quality and reliability for the town of Micanopy and nearby neighbors.

The Jennings battery site, completed in April, is 5.5 MW/5.5 MWh and is located 1.5 miles south of the Florida-Georgia border in the town of Jennings in Hamilton County. This site will continue to improve power reliability through energy storage as an alternative solution to installing new and more costly distribution equipment.

Earlier this year, Duke Energy Florida announced the completion of three battery projects in Gilchrist, Gulf and Highlands counties. The new sites are part of Duke Energy’s commitment to have six battery sites, totaling 50 MW, in operation in Florida this year.

Duke Energy Florida is also developing a 3.5 MW solar plus storage microgrid site at Pinellas County's John Hopkins Middle School. The microgrid will support grid operations and provide backup electric power to the school when it must operate as a special needs hurricane evacuation shelter.

The microgrid consists of a 1 MW solar parking canopy array, a 2.5 MW battery and associated controls, which will store and deploy clean, renewable energy to the school and grid. The project enhances electric service and grid operations for customers.

The groups, in filing a formal response to the proposed electricity-production shifts the utility offered in May to the state Utilities Commission, also make an alternate proposal to reduce carbon dioxide emissions by 70% by 2030 as compared to 2005 levels. They say it would require more solar and wind power and battery storage use than Duke’s plan.

The coalition says its plan would do better with energy savings through efficiency initiatives than what Duke proposes to comply with the landmark 2021 state law that mandates the 70% reduction as well as zero-net CO2 emissions by 2050.

According to a report filed with the commission July 20 prepared by an outside firm hired by the coalition, the mandates can also be met at a lower cost for customers, who are expected to pay higher bills for these shifts.

“Duke’s carbon plan is deeply flawed,” said Luis Martinez, director of Southeast energy at the Natural Resources Defense Council, one of the groups that filed written comments by a deadline July 15. “But this modeling shows that a less costly plan, which also significantly reduces emissions, is possible for North Carolina.”

The law directs the Utilities Commission to tell Charlotte-based Duke Energy how to meet these reductions by the end of the year, and says the seven-member panel can examine “the latest technological breakthroughs to achieve the least cost path,” among other considerations. The commission is holding in-person hearings this month and online meetings next month to take public comment.

Duke spokesperson Bill Norton said July 21 that the utility’s priority remains “to produce the most efficient, reliable, least-cost way to deliver the clean energy our customers deserve and expect” and that Duke looks forward to reviewing proposals and “providing constructive feedback” to the commission.

The coalition, which also includes the North Carolina Sustainable Energy Association, Southern Alliance for Clean Energy and the Sierra Club, is also critical of Duke Energy’s plan because it wants four energy-portfolio alterations it proposed approved, not just one. The utility says that would provide more flexibility and time to evaluate emerging electricity sources.

All four portfolios do envision retiring Duke Energy’s remaining coal-fired power plants in North Carolina by 2035. They also would rely on hydroelectric power storage; an emerging form of small nuclear power plants; and additional natural gas-powered plants, which can provide energy on cloudy or high-demand days.

Natural gas burns cleaner than coal and is considered a bridge fuel while other alternate energy sources are ramped up. But critics say the methane contained in natural gas and that can leak is disproportionately more damaging to the climate than carbon dioxide.

Three of the four portfolios don’t reach the 70% reduction target by 2032 or 2034, but the utility said those plans would result in slightly lower average annual increases on retail power bills through 2035.

The law gives the commission the ability to delay the 2030 target by up to two years, and even longer if regulatory and construction delays for nuclear or wind energy facilities arise, or if the electric grid’s performance is questioned.

Still, “the commission has an obligation to develop a plan to achieve the required carbon reduction requirements set forth in law,” the coalition’s written comments say, calling Duke’s proposal a “Choose-Your-Own Adventure Carbon Plan.”

The utility’s plan covers activities in North Carolina and South Carolina, but the 70% reduction only applies to North Carolina. Duke Energy Carolinas and Duke Energy Progress serve 4.4 million customers in the two states. The coalition said its proposal could trim anticipated higher costs for ratepayers by 2% to 7% through 2030 compared to Duke’s plan.

A 16 MW combined heat and power (CHP) plant is now operating on the southern edge of Purdue University’s West Lafayette, Indiana campus.

The gas-powered plant was built and is owned and operated by Duke Energy. It produces electricity for the company’s Indiana customers and provides thermal energy in the form of steam for Purdue’s heating and hot water needs.

Through an approved agreement, Duke Energy will sell to Purdue the steam the plant produces. The plant can produce up to 150,000 pounds of steam per hour, according to the utility. 

By using steam from the new CHP plant, the university will have more operational flexibility. In the event of an electric grid disruption, the new plant could provide emergency power to help keep the campus running.

In combined heat and power, or cogeneration plants, heat that would otherwise be wasted in the production of electricity is captured and used. Because of this, CHP plants require less fuel to produce the same amount of total energy, resulting in reduced environmental emissions.

According to Duke Energy, the new plant is projected to reduce carbon dioxide emissions by approximately 50,000 metric tons.

In 2019, Purdue trustees approved leasing one acre of land to the utility, which allowed for the building of the CHP plant.

Duke Energy has pursued similar CHP plant partnerships with universities and other institutions.

The utility also has a CHP plant at Clemson University in South Carolina. Duke Energy and Clemson, along with Siemens Energy, teamed up to study the use of hydrogen for energy storage and as a low-carbon fuel source at the Clemson CHP plant. The U.S. Department of Energy (DOE) awarded a $200,000 grant for the pilot research initiative.    

The pilot, called H2-Orange – a nod to hydrogen gas and the collaboration with Clemson University – began in March 2021 and would include studies on hydrogen production, storage and co-firing with natural gas.