The OUCC filed testimony last week to the Indiana Utility Regulatory Commission, arguing that the commission should reject Duke’s proposal due to the “speculative nature of the feasibility and affordability of a CCS system.”

Duke Energy’s request would raise annual revenues for its Indiana electric utility by nearly $492 million, the OUCC said, which would be implemented in two phases. The utility’s testimony and exhibits project that an average monthly residential bill for 1,000 kWh would be $170.67 when new rates are fully implemented in March 2025.

“Duke’s proposal would impose extreme rate shock and unfairly burden its residential customer base, which has experienced significant and worsening affordability challenges,” said Ben Inskeep, Citizens Action Coalition program director. “This rate case is inconsistent with the policy of the State of Indiana and the General Assembly’s repeated emphasis that electric utility bill affordability is a priority. Disappointingly, while Duke proposes a destabilizing rate increase that places a disproportionate burden on residential customers, it has not offered material improvements to its programs that would meaningfully help residential customers with their unaffordable electric bills.”

The OUCC argued its analysis shows that an increase of approximately $184.7 million (6.1%) is warranted instead, based on the case’s evidence and applicable law.

Duke was awarded a Department of Energy (DOE) grant to conduct a front-end engineering design (FEED) study on CCS systems at its Edwardsport Generating Station. The estimated cost of the project is more than $17 million, with an estimated offset of roughly $8 million in federal funding.

In his testimony, Brian Wright, a utility analyst in the electric division for Indiana’s OUCC, noted that Duke’s first CCS feasibility study concluded that CCS was not feasible at Edwardsport due to the “lack of geological formations onsite that could act as a good carbon storage medium.” However, more recent studies at the location have shown that dolomite formations in the area could provide carbon storage capacity.

While Duke Energy has claimed it cannot estimate whether any of its out-of-state subsidiaries could benefit from the study, the OUCC said at “at the very least” the study should improve Duke’s knowledge and experience in evaluating the technological and geographical feasibility of CCS at other sites. Therefore, OUCC argued, the benefits of Duke’s study will likely extend beyond Indiana’s borders, and portions of the cost should be allocated to Duke’s other jurisdictions.

In its petition, Duke Energy said it has been nearly five years since it last filed for a general rate increase, and the test year in the company’s last general rate case was a fully forecasted calendar year 2020 – meaning the case establishing its current rates and charges was filed and the record was closed before the COVID-19 pandemic. Since then, Duke Energy said, the economic climate has changed “significantly,” including increased inflation, increased cost of capital, and Duke Energy Indiana’s capital investments to its electric system.

Duke Energy Carolinas had requested to recover approximately $238 million spent from 2018 to 2023 on closing coal ash basins in South Carolina and North Carolina. Additionally, the utility sought to recover $36 million of previously disallowed costs from a 2018 rate case.

Duke’s coal ash surface impoundments include 13 basins located at coal-fired plant sites: two basins at  W.S. Lee in South Carolina; and the Marshall Ash Basin, the Unit 5 inactive and active basins at Cliffside, the active basin at Belews Creek, retired and active basins at Allen, two basins at Dan River and three basins at Buck, all in North Carolina.

Duke argued that changes in federal regulations had justified its cost-recovery request. Specifically, the utility argued that a January 2022 clarification by the U.S. Environmental Protection Agency (EPA) made federal regulations similar to North Carolina’s stricter Coal Ash Management Act (CAMA). The company contended that because costs mandated by federal regulations are recoverable, the CAMA-related costs should also be recoverable.

However, South Carolina regulators upheld their previous decision, denying recovery of the $36 million previously disallowed and the additional $238 million sought by DEC. PSCSC maintained that costs associated with CAMA, which are stricter than federal coal ash regulations, remain unrecoverable. Regulators said this position was supported by the South Carolina Supreme Court in the previous 2018 rate case.

PSCSC emphasized that future similar costs are only recoverable if they are consistent with and mandated by federal law, setting a clear standard for how utilities should approach cost recovery for environmental compliance in the future.

Coal ash is a byproduct of burning coal in power plants that, without proper management, can pollute waterways, groundwater, drinking water and the air. Coal ash contains contaminants like mercury, cadmium, chromium, and arsenic associated with cancer and various other serious health effects.

In April the EPA finalized a rule requiring the safe management of coal ash placed in areas that were unregulated at the federal level until now. This includes inactive power plants with surface impoundments that are no longer being used and historical coal ash disposal areas at active power plants. The rule applies to historical contamination and inactive units that no longer support current power plant operations. It is not expected to affect current power plant operations.

In a filing to the North Carolina Utilities Commission (NCUC), the utility forecasted even greater electricity demand than projected in the proposal last summer.

Duke said “new economic development wins, including manufacturing and technology projects across the Carolinas” make up the primary driver of the increased electric demand. The utility said annual demand expects to increase 22% by 2030 and 25% by 2035 from 2022 planning cycles — driven by
significant additional economic development activity that took place during 2023.

Notably, according to the Census Bureau, South Carolina’s population grew faster than any state’s in 2023.

“We’re already projecting eight times the load growth we anticipated just two years ago,” said Mike Callahan, Duke Energy’s South Carolina president.

Duke Energy put forth its original resource plan to regulators in August 2023. The company presented three portfolio scenarios but recommended one that achieves 70% CO2 emission reductions from 2005 levels by 2035.

MORE: Duke Energy proposes site for new nuclear in North Carolina

The company’s latest update, its “Portfolio P3 Fall Base,” introduces almost 6.8 GW of additional resources.

The adjustments include the following new proposed resources by 2031: 460 MW of new solar, 175 MW of storage to be paired with solar and 425 MW of new natural gas-fired combustion turbine capacity. The proposed changes also include 2,720 MW of natural gas combined-cycle (NGCC) capacity by 2033, 134 MW of pumped storage hydro by 2034 and 2,400 MW of offshore wind by 2035.

Duke said the new gas plants would hydrogen-capable, including a proposed combined-cycle plant to be built in South Carolina. The 2.4 GW of offshore wind would be built off the coast of North Carolina, subject to necessary regulatory approvals and support.

On Jan. 25, the Public Service Commission of South Carolina (PSCSC) approved Duke Energy’s proposal to provide the proposed adjustments and reset the previously approved regulatory schedule for the process. Under South Carolina’s IRP statute, that new schedule now plans for a hearing in mid-September. Regulators will order a path forward, likely in November 2024.

A pop-up security barrier stopped the car with an Arkansas license plate at the Oconee Nuclear Station near Seneca around 8 p.m., Oconee County Sheriff’s spokesman Jimmy Watt said in a statement.

The driver backed up and tried to drive down a dirt road as Duke Energy security tried to block him in.

The driver tried to hit the guards, then drove through a fence and off the nuclear plant property, Watt said.

He drove a short distance from the plant and shots were fired, although deputies haven’t determined who fired them, Watt said.

The same car showed up an hour before trying to crash through the gate and the driver was asked to leave, deputies said.

A bulletin was issued to police across the U.S. to look for a silver 2002 Toyota Camry with an Arkansas tag 380-VDR, Watt said.

None of the security staff was injured, Duke Energy said.

The Oconee Nuclear Station has three nuclear reactors and started generating power 50 years ago on Lake Keowee.

The plant continues to operate safely, officials said.

“Duke Energy has comprehensive security plans and a well-trained security workforce in place. A vehicle entered an administrative gate, but was not able to access the plant due to our multiple layers of security,” Duke Energy said in statement.

The system will be located at Duke Energy’s DeBary Plant in Volusia County, Florida.

It will use the existing 74.5 MW DeBary solar plant to power two 1 MW electrolyzers. The resulting hydrogen from electrolysis will delivered to nearby, reinforced containers for safe storage.

During times when energy demand is highest, Duke Energy said the hydrogen will be combusted in an onsite turbine that will be upgraded using GE technology to run on a natural gas/hydrogen blend or up to 100% hydrogen. The utility said this will be the nation’s first combustion turbine operating to run on such a high percentage of hydrogen.

Duke Energy said the unit will be commissioned on a variety of blends from 25-100% hydrogen. The turbine will be “fully capable of consistently combusting on said varieties as well as 100% hydrogen when placed in service,” the utility said.

Duke Energy, Sargent and Lundy and GE Vernova are all partners in the effort.

Construction of the demonstration project will begin by the end of 2023 and could take about one year to complete. Duke Energy anticipates the system will be installed and fully functioning in 2024.

Utility officials said the DeBary hydrogen system is part of its Vision Florida program. The projects in this program may include up to four Emergency Relief Microgrid projects, a floating solar pilot project at the Hines generating station, an investment in some form of hydrogen power and solar plus storage projects. Total costs for all projects would not exceed $100 million.

The hydrogen end-to-end system is not part of one of the seven regional hydrogen hubs selected by the federal government to negotiate funding.

“While it is disappointing that the Southeast Hydrogen Hub Coalition was not selected for Department of Energy (DOE) funding, Duke Energy remains hopeful that hydrogen will play an important role in our clean energy transition,” said a Duke Energy Florida spokesperson. “Duke Energy will continue to seek opportunities to partner with DOE, peer utilities, and other stakeholders to advance clean hydrogen in ways that will benefit our customers and our communities.”

Duke Energy has a goal to reach net-zero carbon emissions from electricity generation by 2050. The company has interim carbon emission targets of at least 50% reduction from electric generation by 2030, 50% for Scope 2 and certain Scope 3 upstream and downstream emissions by 2035, and 80% from electric generation by 2040.

Alex Glenn, CEO of Duke Energy Florida and Midwest took the keynote stage at POWERGEN International last month and spoke about the challenge of net-zero.

He then spoke with Clarion Energy’s own Jenn Runyon backstage.

“I would say our greatest challenge is also our greatest opportunity,” Glenn said, on how the energy sector can transform its generating sources and grid to meet net-zero goals.

Duke Energy’s own goal is to reach net-zero emissions by 2050. In its climate report from October 2022, the company noted it also has an interim target of 80% emission reductions from 2005 levels by 2040.

Glenn noted four important keys to success: Maintaining 24/7 reliability for customers, technology and supply chain improvements, affordability, and engaging the support of stakeholders who may have different views.

“It’s an exciting time to be in our business, and I’m looking forward to the next ten years which are going to be changing dramatically for our industry,” Glenn told Runyon backstage.

WATCH THE INTERVIEW:

On the keynote stage, Glenn told POWERGEN attendees Duke expects to rely on zero-emission load following resources, which haven’t been commercialized yet. He mentioned that hydrogen and nuclear power breakthroughs look like potential promising solutions.

“We, in this room, have to figure this out,” he told attendees.

“My ask of you today is three things,” he said, challenging attendees to think about the following: “‘How do I fit into this transformation?  How am I going to contribute and where am I going to start to change the world?’’

Duke Energy plans to add 30 GW of renewables by 2035 and be out of coal production by 2035.

The utility has said continuing to operate existing nuclear generation and adding new small modular reactors (SMR) are essential to maintaining emission reduction progress and achieving net-zero goals.  

In its report the company touted a solar to 100% green hydrogen-capable combustion turbine in Florida, with the goal to be operational by 2024. Duke Energy not provide more details on the project.

Duke Energy is also partnering with Clemson University and Siemens Energy to potentially produce, store and co-fire hydrogen at the utility’s CHP plant on Clemson’s campus.

Idaho’s largest solar plant is now commercially operable.

This is Duke Energy’s first utility-scale renewable energy project in the Potato State.

The 120 MW Jackpot Solar project will provide energy to Idaho Power through a 20-year power purchase agreement.

SOLV Energy completed the engineering and construction of the project, located on 952 rural acres south of the city of Twin Falls. Duke will own and operate the project.

Duke Energy’s current generation mix includes more than 10,000 MW of solar and wind energy. Duke Energy has set a goal of reaching 16,000 MW of renewables by 2025 and 47,000 MW by 2050.

In a February 2022 call with investors, Duke Energy CEO Lynn Good said the utility plans to double its renewable energy capacity by the end of the decade, and stop generating electricity from coal by 2035.

Duke has retired 56 coal units for a total of 7.5 GW of capacity since 2010, Good said. The utility will spend around $4 billion on hydrogen-enabled natural gas generation to better ensure reliability in the absence of coal.

Idaho is ranked 28th among U.S. states in solar installed with 630 MW, according to the Solar Energy Industries Association (SEIA).

At 108 MW, Grandview PV Solar Two is one of the largest solar projects in Idaho. It was installed in 2016.

Following 13 days of hearings, the North Carolina Utilities Commission (NCUC) issued an order Dec. 30 adopting Duke Energy’s initial Carbon Plan. Mirroring North Carolina’s larger decarbonization plan, the goal is to achieve a 70% reduction in CO2 emissions at Duke Energy plants in the state, from 2005 levels by the year 2030 and carbon neutrality by 2050.

The order requires Duke to remodel resource additions to achieve reduction mandates, factoring impacts of the Inflation Reduction Act (IRA), Infrastructure Investment Jobs Act (IIJA) and other future legislative changes. The utility would need to file a new proposal with NCUC by Sept. 1, 2023, to be considered by the commission in early 2024.

Rather than approve a single, preferred portfolio of generation assets, the commission directed Duke to:

• Conduct two competitive procurements between 2023-2024, targeting 2,350 MW of new solar generation to be placed into service by 2028.

• Procure 1,000 MW standalone battery storage and 600 MW of battery storage paired with solar generation.

• Upgrade necessary transmission facilities to interconnect new solar generation.

• Retire its remaining coal-fired plants, more than 9,000 MW, by 2035.

• Incur project development costs associated with additional pumped storage hydro at the Bad Creek Hydroelectric Station in Oconee County, South Carolina.

• Study and consider the acquisition and development of wind lease areas off the coast of North Carolina.

• Seek to extend the licenses for its existing nuclear fleet and to incur project development costs associated with new nuclear generation.

• Engage with onshore wind stakeholders and economically model utility-owned onshore wind in its next round of modeling.

• Plan for the addition of combustion turbine and combined cycle natural gas-fired generating capacity and address concerns about the availability of firm transmission capacity to North Carolina in future proceedings.

• Develop targeted plans for engaging low-income, minority, and rural communities.

“The emergency outage events this month particularly underscore the need for an orderly transition away from fossil fuels to low and zero carbon dioxide emitting generating resources while maintaining or improving the reliability of the electric grid,” the commission said in a statement.

The law requires the NCUC to review and adjust the Carbon Plan every two years.

A statement from Duke Energy Dec. 30 reads in part:

“We believe this is a constructive outcome that advances our clean energy transition, supporting a diverse, ‘all of the above’ approach that is essential for long-term resource planning. We’ve already made incredible progress, retiring two-thirds of our aging coal plants in North Carolina and South Carolina and reducing emissions by more than 40% since 2005 – we will continue this ongoing work of lowering carbon emissions to reduce risk for our customers while balancing affordability and reliability.”

The full carbon plan can be found here.

A newly-formed coalition of some of the largest utilities in the U.S. will pursue a “six-state hydrogen hub” in the Southeast and plans to apply for funding from an $8 billion U.S. Department of Energy program.

The coalition includes Dominion Energy, Duke Energy, Louisville Gas & Electric Company and Kentucky Utilities Company (LG&E and KU), Southern Company, and the Tennessee Valley Authority (TVA), along with Battelle and others, according to an announcement Nov. 1.

Other members of the group will include hydrogen users from a variety of industries in Alabama, Georgia, Kentucky, North Carolina, South Carolina and Tennessee.

Many believe hydrogen is poised to play a major role in addressing climate change. In power generation, the advantages of hydrogen include fuel flexibility through the ability to blend hydrogen with natural gas, fuel security through integration with hydrogen storage and the flexibility to follow loads from variable generation.

Major OEMs like GE, Siemens and Mitsubishi Power have been focusing their efforts on hydrogen combustion in gas turbines, particularly for large-scale generation.

MORE: Should we just burn hydrogen for electricity?

“By working together, the coalition can focus on developing scalable, integrated projects at key locations across the entire Southeast in support of these carbon-reduction goals and encourage the broad-based development of a regional energy ecosystem that will allow members to deploy hydrogen as a decarbonization solution for customers and communities,” said a joint release from the utilities.

DOE’s $8 billion regional hydrogen hub program comes from the Infrastructure Investment and Jobs Act (IIJA) passed in 2021.

According to program criteria, hubs would need to demonstrate the production, processing, delivery, storage and end use of clean hydrogen.

Hydrogen hubs would be sited in different regions of the U.S. DOE said it envisions selecting between 6-10 hubs at a total of $6-7 billion, depending on the number, quality and funding needs of applications received. The remaining $1-2 billion could be reserved for future hub launches or other supporting activities.

To the maximum extent possible, the DOE would choose projects based on several objectives:

-At least one hub would produce hydrogen from fossil fuels, one hub from renewable energy, and one hub from nuclear energy.

-At least one hub would demonstrate the end-use of clean hydrogen in the electric power generation sector, one in the industrial sector, one in the residential and commercial heating sector and one in transportation.

-Each hub would be located in a different region of the United States and leverage energy resources abundant to that region, including at least two hubs in regions with abundant natural gas resources.

-DOE would give priority to hubs likely to create opportunities for skilled training and long-term employment to the largest number of residents in the region.

Duke Energy published its latest climate report Oct. 4, highlighting planned investments to the company’s generating fleet.

The company said it plans to increase capital investment for its seven regulated utilities to $145 billion over the next decade. $40 billion of that total would be for investments in zero-carbon generation sources, such as renewables, battery storage resources and hydrogen-powered natural gas technologies. It would also include extending the life of its nuclear fleet.

Duke Energy’s goal is to reach net-zero emissions by 2050. In its climate report, the company noted it also has an interim target of 80% emission reductions from 2005 levels by 2040. Duke Energy said it has already reduced emissions from its generating fleet by 44% through the end of 2021.

See the climate report here

Hydrogen

In its climate report, Duke Energy said it is implementing a solar to 100% green hydrogen-capable combustion turbine in Florida, with the goal to be operational by 2024. The company did not provide more details on the project, so we have reached out to get more details.

Duke Energy is also partnering with Clemson University and Siemens Energy to potentially produce, store and co-fire hydrogen at the utility’s CHP plant on Clemson’s campus.

The company is also partnering with Wabash Valley Resources on a DOE -funded front-end engineering design study of biomass to-net-zero-hydrogen production in Indiana.

Renewables

By 2035, Duke Energy said it expects to have 30,000 MW of renewables on its system. In September the utility completed a 700 MW solar project portfolio in Florida, one of its fastest growing states for solar power.

Completion of the 74.9 MW Charlie Creek Solar Power Plant in Hardee County marked the last of 10 solar projects to be brought online from 2018 through 2022.

By 2024, the company believes its solar portfolio in Florida will include 25 solar plants, which would provide about 1,500 MW of capacity.

Duke Energy also recently became one of two offshore wind lessees for the Carolina Long Bay area east of Wilmington, North Carolina. The lease could support the development of up to 1.6 GW of offshore wind.

New nuclear

In its climate report, Duke Energy said continuing to operate existing nuclear generation and adding new small modular reactors (SMR) are essential to maintaining emission reduction progress and achieving net-zero goals.  

The company serves an advisory role on the TerraPower-led team that is working to demonstrate GE Hitachi’s Natrium fast sodium reactor with molten salt storage. The project received one of two U.S. Department of Energy (DOE) awards through the Advanced Reactor Demonstration Program (ARDP) in 2020.

Duke Energy is also an advisory board member for NuScale, which is working toward a six-unit pilot SMR in Idaho by 2030. NuScale is the first SMR design to receive certification by the Nuclear Regulatory Commission (NRC), but it has not yet received its operating license.

In Indiana, Duke Energy is working with Purdue University on an SMR feasibility study to determine how to best meet the energy needs of the university and the state using nuclear.

Finally, Duke Energy is a member of the Market Development Advisory Committee for General Fusion, a Canadian company developing a fusion power plant technology.

Long-duration energy storage

Duke Energy is evaluating the potential for increased pumped-storage capacity to support renewables integration in the Western Carolinas. The utility has owned and operated pumped-storage hydro stations in the region since the 1970s.

The utility also said it is piloting multiple technologies, including a vanadium flow battery with the University of Central Florida; Honeywell’s new nonflammable flow battery and EOS’s Znyth Gen 3.0 zinc bromine battery at Duke Energy’s Emerging Technology Innovation Center in Mount Holly, North Carolina; and EnerVenue’s nickel-hydrogen battery at our McAlpine Creek Substation in Charlotte, North Carolina.

Duke Energy is also partnering with the Electric Power Research Institute (EPRI) to study the cost and performance of deploying Hydrostor’s advanced compressed air energy storage technology at an existing coal site in North Carolina.

How new laws help

Duke Energy believes the Inflation Reduction Act (IRA) will help drive advancements in hydrogen and storage technologies, as well as strengthen the supply chain for clean energy resources such as hydrogen, new nuclear and advanced energy storage.

Duke Energy says its preliminary modeling indicates that the IRA will reduce the cost of its energy transition through the 2030s, bringing down costs with the legislation’s tax credits for solar, wind, hydrogen, storage and new and existing nuclear.

The utility also expects to benefit from the IIJA, also known as the bipartisan infrastructure bill. Enacted in late 2021, the IIJA provides more than $60 billion for clean energy technology development and grid modernization.