The oil and gas giant is building a massive natural gas-fired plant which is already in early development stages, the New York Times reported. The company said its carbon capture and storage (CCS) system could trap and store over 90% of the plant’s CO2 emissions.

This would be the first time Exxon is developing a power plant that wouldn’t electrify its own operations. The company has developed 5.5 GW of power projects since 2001 in states like Texas and Louisiana.

Exxon believes data centers could account for up to 20 percent of the total addressable market for CCS in 2050, company executives said in a corporate plan update on Wednesday.

This particular gas-fired plant would not be connected to the grid, avoiding grid connection challenges and meaning it could come online faster. Executives said the company has previously developed 800 MW of islanded power generation.

The future adoption of CCS in power generation likely depends on a variety of factors, like changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions and the development of clean energy technologies that could affect the demand for CCS.

Earlier this week NET Power, with the help of several partners, said it plans to develop 1 GW of gas-fired power with its Allam-Fetvedt Cycle CO2 capture system.

Also this week, a new project in the UK was approved to proceed with its plans to create the world’s first gas-fired power station with CCS. NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up could be as soon as 2028.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. Demand for computing power from data centers, fueled by artificial intelligence and other new technologies, requires enormous amounts of power.

Technip Energies, along with GE Vernova and construction partner Balfour Beatty – and with the support of technology partner Shell Catalysts & Technologies – received a notice to proceed by NZT Power Limited to execute a major contract for the Net Zero Teesside Power (NZT Power) project in the United Kingdom.

NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up is expected in 2028, supporting the UK Government’s Clean Power 2030 ambition. The project aims to be the world’s first gas-fired power station with carbon capture and storage. Up to 2 million tons of CO₂ per year could be captured at the plant and transported and permanently stored by the Northern Endurance Partnership, the companies said.

NZT Power has reached financial close and has issued a full notice to proceed to the Technip Energies-led consortium to start the full engineering procurement and construction (EPC) package for the onshore power, capture and compression contract. Financial close follows the UK government’s recent announcement of a £21.7 billion pledge for projects to capture and store carbon emissions from energy, industry and hydrogen production.

A “major” award for Technip Energies is a contract award representing above €1 billion of revenue. The award will be included in backlog in Q4 2024, the company said.

Technip Energies and GE Vernova, with the support of infrastructure group Balfour Beatty, plan to deliver a combined cycle plant and associated carbon capture system. Technip Energies will lead the integration of a carbon capture system using its Canopy by T.EN solution, powered by Shell’s CANSOLV CO₂ Capture System. The plant will be powered by GE Vernova’s 9HA.02 gas turbine, a steam turbine, a generator, a heat recovery steam generator, and an exhaust gas recirculation (EGR) system.

“We believe CCUS technology can be crucial to help decarbonize the planet, and we welcome the commitment from the UK government to invest in its implementation as well as NZT Power’s trust in our technology,” said Maví Zingoni, CEO, Power at GE Vernova. “Flagship projects like Net Zero Teesside Power can give the industry foundations to grow. We look forward to powering the station with our advanced H-Class combined cycle technology, as well as proceeding with the first commercial use of our Exhaust Gas Recirculation system and integration technologies, which aim to support carbon abatement by boosting the efficiency and performance of carbon capture.”

Canada-based TC Energy has withdrawn from Project Tundra, according to Politico’s E&E News. TC Energy was a primary sponsor, along with Minnkota Power Cooperative.

TC Energy played a pivotal role as a partner in the development of Project Tundra, and their contributions provided tremendous value,” a Minnkota Power Cooperative spokesperson said in a statement provided to Power Engineering. “While we remain optimistic about advancing the project, securing capital resources will be essential to reaching a final investment decision.”

Project Tundra aims to capture carbon from the Milton R. Young Station, a coal-fired plant near Center, North Dakota. The project would use Mitsubishi Heavy Industries’ KS-21 solvent to capture CO2, which would be permanently stored in saline geologic formations beneath and surrounding the power plant. The storage site is approved for a Class VI well permit.

Minnkota had said it plans to retrofit the coal-fired plant’s 430 MW Unit 2 to capture up to 90% of its CO2 emissions. Unit 2 is a cyclone-fired wet bottom boiler from Babcock & Wilcox. The project could capture an annual average of 4 million metric tons of CO2, according to project leaders said.

Project Tundra received federal funding from the U.S. Department of Energy (DOE) last year through two separate totaling nearly $400 million. This was in addition to another $43 million received from the federal government in 2020.

Carbon capture is seen by proponents as an emerging technology that could keep fossil-fired plants viable while reducing emissions. Under the Biden Administration’s EPA Power Plant Rule, coal- and new natural gas-fired plants would have to capture their carbon or close by various compliance dates in the 2030s.

Opponents of the rule, which may not survive the first few weeks of the new Trump Administration, have expressed that CO2 capture systems are costly and energy-intensive.

Officials with the National Rural Electric Cooperative Association (NRECA) noted in court filings earlier this year that Project Tundra sits atop ideal geology for storage, has been in planning for nearly a decade, and has used government funding for two-thirds of the costs so far, yet still would not meet the 90% capture rate.

They also said other variable factors that could further delay the project include labor and supply chain constraints.

The Minnkota Power spokesperson said the co-op continues to assess federal funding opportunities, potential EPA compliance obligations and ongoing supply chain and inflationary pressures. The spokesperson said the co-op looks forward to a final investment decision “when the necessary conditions align.”

We have reached out to TC Energy for comment and will continue providing updates to this story.

The U.S. Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management released the official findings of the GE Vernova-led front-end engineering design (FEED) study, Retrofittable Advanced Combined-Cycle Integration for Flexible Decarbonized Generation.

The study evaluated retrofitting Southern Company subsidiary Alabama Power’s James M. Barry Electric Generating Plant, located in Bucks, Alabama, with technology capable of capturing up to 95% of the plant’s CO₂ emissions. GE Vernova said the study demonstrated that the integration of the company’s EGR system could lead to a reduction of more than 6% of the total cost of the carbon capture facility, as compared to installing carbon capture without the EGR system.

The study was completed in collaboration with Southern Company, Linde, BASF and Kiewit, and explored the benefits of close integration between a natural gas combined-cycle (NGCC) plant and a carbon capture system. GE Vernova’s measures and technologies explored in the study included the use of NGCC steam in the carbon capture system facility, potential gas turbine upgrades, installing NGCC and carbon capture control systems and employing GE Vernova’s EGR system, which reintroduces part of the exhaust gas back into the gas turbine inlet.

“GE Vernova is grateful for the Department of Energy’s support of this study, the first of its kind to explore EGR technology applied in a gas power carbon capture plant” said Jeremee Wetherby, GE Vernova Carbon Solutions Leader. “We developed a holistic approach considering various integration measures building on our long history and expertise in power plant engineering, operation, upgrades and controls. Carbon capture is a crucial pathway to lowering carbon emissions from power generation to near-zero levels, and we are pleased with the benefits projected by the study – which naturally can vary from site to site but represent a valuable indicator of the possibilities at similar sites.”

The study said the effects of adding a carbon capture system to an NGCC power plant could be reduced through a series of integration measures, including the EGR system. GE Vernova has developed EGR systems for two decades, initially for nitrogen oxide (NO_x) control and part-load efficiency benefits. In addition to this study, GE Vernova has demonstrated the commercial readiness of F- and H-class combustors operating with EGR at GE Vernova’s test facility in Greenville, South Carolina.

This study recognized the potential of an EGR system to deliver the following benefits as compared to a non-EGR system:

• Large reduction of carbon capture facility footprint and cost of absorber
• Lower operating costs due to reduced amine degradation
• Less energy-intensive separation due to higher concentration of CO₂ in flue gas directed to the carbon capture system
• More steam turbine power output because of lower steam consumption

“As a provider of CO₂ capture technology, we commend DOE’s leadership in advancing gas power decarbonization technology towards a clean and reliable energy future. The results of this FEED study underpin Linde’s belief that a collaborative approach between technology providers, end-users, and other stakeholders is essential in driving innovation and cost reduction in CO₂ capture. We are committed to working with DOE and other partners to help decarbonize industry,” said Dominic Cianchetti, Senior Vice President, Region Americas, Linde.

The combined-cycle facility began commercial operations in 2007, and its power is sold to the Electric Reliability Council of Texas (ERCOT).

Calpine has recently been making moves to develop or buy new power generation in multiple regions.

After seeing positive market signals in Texas, Calpine began redevelopment efforts in the Lonestar State last year. The company is reportedly on track to add over 1,000 MW of generation to its Texas fleet over the next few years.

Additionally, in response to skyrocketing energy prices within PJM Interconnection, Calpine plans to explore multiple new locations for generation capacity, particularly in Ohio and Pennsylvania. The company also said it would explore a potential expansion of its existing fleet. Over the last decade, Calpine has brought online 1,600 MW of new gas-fired generation within PJM territory. PJM is the largest grid operator in the U.S.

The company’s fleet is also involved in multiple carbon capture demonstrations.

Earlier this year, Calpine announced that it executed a cost share agreement with the U.S. Department of Energy (DOE) Office of Clean Energy Demonstrations (OCED) for a full-scale carbon capture demonstration project at its Baytown Energy Center near Houston.

The Baytown Decarbonization Project is designed to capture 95% of CO2 emissions from two of the three turbines at the company’s Baytown Energy Facility, enabling the facility to produce electricity as well as steam for collocated industrial use. Calpine began the first phase of the DOE cooperative agreement, with other phases to follow upon successful completion of phase one and finalization of plans for subsequent phases.

In addition to the company’s Baytown project, Calpine continues to advance its similarly sized Sutter Decarbonization Project in California, for which it also recently executed a cost share agreement with OCED. The Sutter Decarbonization Project would be designed to capture 95% of carbon emissions from Sutter Energy Center. Calpine now plans to begin the first phase of the DOE cooperative agreement, which will support the engineering and design of the project. Sutter Energy Center is located in Yuba City, California. The 550 MW combined-cycle plant became commercially operable in 2001.