Emissions

In building its carbon rule, EPA gave a nod to these power plants

The agency cited multiple examples of existing and planned power generating projects that use carbon capture and sequestration and hydrogen technologies

The U.S. Environmental Protection Agency (EPA) cited multiple examples of existing and planned power generating projects that use carbon capture and sequestration and hydrogen technologies, which are bedrock strategies for achieving its newly proposed carbon emission reductions.

One GHG reduction technologies is carbon capture and sequestration (CCS), a technology that can capture and permanently store CO2 from power plants. 

In practice, exhaust gases from most combustion processes are at atmospheric pressure with relatively low concentrations of CO2. Most post-combustion capture systems use liquid solvents (most commonly amine-based) in a scrubber column to absorb the CO2 from the flue gas. This CO2-rich solvent is then regenerated by heating the solvent to release the captured CO2. The high purity CO2 is then compressed and transported, generally through pipelines, to a site for geologic sequestration.

In its proposed rulemaking, EPA said that process improvements, the availability of better solvents, and other advances have resulted in a decrease in the cost of CCS in recent years. It said the cost of CO2 capture, excluding any tax credits, from coal-fired power generation is projected to fall by 50% by 2025 compared to 2010. 

In addition, policies such as the 2022 Inflation Reduction Act (IRA) support the deployment of CCS technology and are expected to further reduce the cost of implementing CCS by extending and increasing the tax credit for CCS under Internal Revenue Code section 45Q.

EPA pointed to several examples CCS being used at power plants. These include SaskPower’s Boundary Dam Unit 3, a 110 MW lignite-fired unit in Saskatchewan, Canada, which EPA said has achieved CO2 capture rates of 90% using an amine-based post-combustion capture system retrofitted to the existing steam generating unit.

Amine-based carbon capture has also been demonstrated at AES’s Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants.

CCS was applied to an existing combined cycle combustion turbine at the Bellingham Energy Center in south central Massachusetts. The 40 MW slipstream capture facility at Bellingham operated from 1991 to 2005 and captured 85% to 95% of the CO2 in the slipstream.

In Scotland, the proposed 900 MW Peterhead Power Station combined cycle power plant with CCS is in the planning stages and could capture 90% of its CO2 emissions.  

An 1,800 MW combined cycle unit in West Virginia is planned to use CCS and could enter service later this decade. EPA said its economic feasibility was partially credited to the expanded IRC section 45Q tax credit for sequestered CO2 provided through the IRA.

Hydrogen co-firing

EPA said that industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades. More recently, power sector combustion turbines in the have begun to co-fire hydrogen to generate electricity. 

EPA said that new utility combustion turbine models have demonstrated the ability to co-fire up to 30% hydrogen. It said developers are working toward models that will be ready to combust 100% hydrogen by 2030. It noted that several utilities already are co-firing hydrogen in test burns and some have announced plans to move to combusting 100% hydrogen in the 2035–2045 timeframe.

EPA pointed to the Los Angeles Department of Water and Power’s (LADWP) Scattergood Modernization project that includes plans to have a hydrogen-ready combustion turbine in place when the 346 MW combined cycle plant (potential for up to 830 MW) begins initial operations in 2029. LADWP foresees the plant running on 100% electrolytic hydrogen by 2035. 

In addition, LADWP also has an agreement in place to buy electricity from the Intermountain Power Agency project (IPA) in Utah. IPA is replacing an existing 1.8 GW coal- fired plant with an 840 MW combined cycle turbine that developers expect to initially co-fire 30% electrolytic hydrogen in 2025 and 100% hydrogen by 2045.

In Florida, NextEra Energy announced plans to operate 16 GW of existing natural gas-fired combustion turbines with electrolytic hydrogen as part of the utility’s Zero Carbon Blueprint to be carbon-free by 2045.

Duke Energy Corp., which operates 33 gas-fired plants across the Midwest, the Carolinas, and Florida, has outlined plans for full hydrogen capabilities throughout its future turbine fleet. EPA quoted a utility statement that said, “All natural gas units built after 2030 are assumed to be convertible to full hydrogen capability. After 2040, only peaking units that are fully hydrogen capable are assumed to be built.”

In addition to those utility announcements, several merchant generators operating in wholesale markets are also signaling their intent to ramp up hydrogen co-firing levels after initial 30% percent co-firing phases. 

The Cricket Valley Energy Center (CVEC) in New York is retrofitting its combined cycle power plant starting in 2022 as a first step toward the conversion to a 100% hydrogen fuel capable plant. 

The Long Ridge Energy Terminal in Ohio, which has co-fired a 5% hydrogen blend at its 485 MW combined cycle plant, said that its technology has the capability to transition to 100% hydrogen over time as its low-GHG fuel supply becomes available.

EPA also said that Constellation Energy also is exploring electrolytic hydrogen co-firing across its fleet. It estimated costs for blend levels in the range of 60-100% at around $100/kW for retrofits and noted that equipment manufacturers are planning 100% hydrogen combustion-ready turbines before 2030.

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