EPA Proposes Emission Limits for Fossil Fuel-Fired Power Plants – Is Industry Up for the Challenge?
EPA Proposes Emission Limits for Fossil Fuel-Fired Power Plants – Is Industry Up for the Challenge?
by: Noah Gannon | August 16, 2023
Boyertown, Pennsylvania (August 17, 2023) – On August 8, 2023, the public comment period ended for the Environmental Protection Agency (EPA) proposed Clean Air Act emissions limits and decarbonization technology guidance for fossil fuel-fired power plants in the United States. The proposed rule considers how different Electricity Generating Units (EGUs) are used, including the resource type and load capacity, and prescribes control technologies such as Carbon Capture and Storage (CCS) and Hydrogen co-firing to reduce emissions.
Scientists estimate the proposal, if enacted, will reduce 617 million tonnes of CO2 emissions by 2042. Additionally, economists value potential associated benefits at $64-$85 billion, including health benefits, such as 1,300 avoided premature deaths and 300,000+ cases of asthma symptoms.
In anticipation of potential legal challenges, the EPA structured the current proposal within the context of the recent 2022 West Virginia vs. EPA decision in which the Supreme Court limited the EPA’s rule-making authority.
The proposed rule presents both challenges and opportunities for the energy industry. Challenges include extensive capital expenditure costs, limited CCS and hydrogen supply and infrastructure, a volatile regulatory climate, and a lack of regulatory frameworks to enable use and large-scale deployment of these projects.
However, CCS and low-GHG hydrogen offer asset owners the opportunity to entrench their existing infrastructure investments within the energy landscape and provide a dispatchable low-carbon energy resource to utilities looking to balance daily and seasonal renewable energy fluctuations.
Alternatively, some asset owners may consider reducing capacity to under 20% to avoid implementing any controls or under 50% to qualify as an intermediate load with less stringent standards. There will be impacts on grid reliability if a mass shutdown of gas-powered resources occurs before the buildout of batteries and other forms of energy storage.
Proposed Technology-Based Standards
The proposal consists of Technology-Based Standards designed to allow the power sector continued resource and operational flexibility, facilitate long-term planning, and consider the cost-effectiveness of emissions controls. Specifically, the proposal requires CO2 emissions control at fossil fuel-fired power plants starting in 2030 and phases in increasingly stringent CO2 control requirements over time. The proposed requirements vary by:
- The type of unit rather than fuel type (i.e., new or existing, combustion turbine or utility boiler, coal-fired or natural gas-fired)
- How frequently it operates (base load, intermediate load, or low load (peaking), and
- Its operating horizon (i.e., planned operation after certain future dates).
These variations hope to achieve the Standard’s goals of cost-effectiveness and operational flexibility. For example, the installation of controls such as CCS for coal and gas plants and low-GHG hydrogen co-firing for gas plants are more cost-effective for power plants that operate at a greater capacity, more frequently, or over extended periods. The table below outlines the Best System of Emissions Reduction (BSER) by phase and unit type.
Low-GHG Hydrogen Pathway
As shown above, the low-GHG hydrogen pathway offers an incremental approach through hydrogen co-firing to reduce emissions with increasing volume as hydrogen supply networks are developed. The proposed carbon intensity of low-GHG hydrogen at 0.45 kgCO2e/kgH2, “well-to-gate,” is exceptionally aggressive and much lower than all international Low Carbon Standards, as shown in the graphic below. As a result, this standard may be met with blue (coal/natural gas feedstock) and green (renewable energy feedstock) hydrogen, as well as pink (nuclear-powered) hydrogen.
The International Energy Agency predicts total hydrogen production will need to be 180 MMT by 2030, up from 90 MMT today, to reach net zero emissions by 2050. Currently, low-GHG hydrogen production represents only 1% of total hydrogen production, challenging project developers to increase product while greening their hydrogen process with renewable resources to meet new regulatory requirements, like the EPA’s proposed standards.
At current U.S. power demand and portfolio, about 1.5 trillion kWh is produced annually by gas turbines subject to this ruling . Assuming a standard combined cycle unit has a 60% overall efficiency, 30% hydrogen co-firing would require 747 billion kWh of raw energy, almost 10X current hydrogen production levels. In creating this rule, the EPA attempts to dramatically scale hydrogen demand in the U.S.
The energy needed to produce hydrogen leads to as much or more energy used to produce hydrogen as is recovered when the hydrogen burns.
If project developers can create a supply, hydrogen transportation will present another hurdle. Hydrogen can be transported by pipeline, tanker, rail, and truck, but ammonia and liquefication are the best delivery methods for longer distances and have the biggest impact on costs. Approximately 1,600 miles of hydrogen pipelines are currently operating in the U.S., primarily in the Gulf Coast region, in support of petroleum refineries and chemical plants . Converting the nations existing natural gas pipeline to carry a blend of hydrogen would only require modest upgrades compared to more substantial modifications for pure hydrogen. Industry initiatives and the DOE H2Hubs program take a grassroots approach to increasing regional engagement.
Importantly, the Inflation Reduction Act (IRA) includes Hydrogen Production Tax Credits, which offer producers $3/ kg H2 for ten years for low-GHG carbon intensity for projects that begin construction by 2033 with retrofit facilities eligible. While direct pay and transferability allow revenue streams for companies with low tax liabilities, the credit cannot be stacked with the Carbon Capture and Sequestration Credit (45Q), which may disincentive co-locating CCS and low-GHG hydrogen controls.
Using electricity to produce hydrogen, only to be re-converted into electricity through co-firing, results in as much or more energy being lost than is recovered for grid use. This makes hydrogen co-firing for electricity a much less efficient process than traditional electricity transmission. We believe hydrogen is better applied in the transportation industry given its quick refueling, easy adoption, and decent conversion efficiency for fuel cells and hydrogen-compatible ICEs. This leaves CCS as the most practical and economically viable control technology for fossil fuel-fired power plants in the U.S.
Carbon Capture and Sequestration (CCS) Pathway
According to the IEA, Carbon Capture and Sequestration projects capture more than 45 million tCO2 annually from 40 facilities globally. Although CCS deployment has increased with over 500 projects in various stages, the IEA estimates that deployment remains substantially below the level required to achieve net zero emissions by 2050. Similar to low-GHG hydrogen, project developers face a handful of challenges in meeting CCS demand generated from new regulatory requirements:
First, CO2 lacks national pipeline infrastructure but has a history of industrial uses, primarily enhanced oil recovery (EOR). This infrastructure is primarily in the Gulf Region and the Dakotas. Last month, Exxon Mobile bought Denbury, the largest CO2 pipeline network in the country, in a bid to accelerate Exxon’s carbon capture goals.
The Department of Energy has also prioritized CO2 transportation and sequestration, with $8.5B earmarked for CCS in the infrastructure package. The bill envisions four regional direct air capture hubs, prioritizing localized networks over a nationwide pipeline.
The IRA included a Carbon Capture and Sequestration Credit (45Q), which offers up to $85 per tonne for storage of CO2 in deep saline geologic formations. For other uses, such as low-carbon fuels, chemicals, building materials, or enhanced oil recovery (EOR), the credit falls to $60 per tonne, with direct pay for the first five years after the equipment is placed in service.
States will have 24 months to submit plans establishing performance standards and transparency requirements for power plants within their state borders if the proposed rule is enacted, as shown in the timeline below. Plans must include an environmental justice analysis of impacted communities and meaningful engagement with affected stakeholders. States are encouraged, but not required, to develop emissions trading and averaging schemes. A less stringent standard may be requested for facilities with long-remaining useful lives.
The future of this legislation is not certain. Four major grid operations — PJM Interconnection, Midcontinent Independent System Operator, Southwest Power Pool, and the Electric Reliability Council of Texas — have filed joint comments that grid reliability will “dwindle to concerning levels.” A coalition of 21 states, led by West Virginia, have also filed comments warning about the legal implications of the rule. With the 2024 presidential election approaching, a Republican administration could repeal this rule before the enforcement period begins. Individual states and joint ISOs/RTOs must decide if they will proactively plan for controls or wait and see, hoping external players derail technology implementation and CO2 standards.
Over the last 14 years, ClimeCo has supported corporates in hard-to-abate sectors and energy asset owners in decarbonizing their operations by evaluating policy updates and incentives, supporting decarbonization project implementation, leveraging environmental markets, and becoming trusted decarbonization technology experts. Please inquire with the ClimeCo team to learn more about our case studies and service offerings.