TOPIC #1
EPA Issues Power Plant Greenhouse Gas Rule
The EPA finalizes a rule with major implications for existing coal-fired generation and new gas-fired units.
EPA Modifies and Finalizes Greenhouse Gas Rule
In May 2023, EPA proposed a greenhouse gas (GHG) rule for fossil-fired power plants.
- Motivating the proposal is the Biden administration’s “all-of-government” approach to climate policy.
- The proposed rule covered both new and existing fossil-fired generation: coal, oil, and gas. It set GHG emissions standards with time and levels differentiated by unit fuel type and capacity, new or existing unit, planned retirement date, and duty cycle (capacity factor).
- The proposed rule set a performance standard—based upon a “best system of emissions reduction” (BSER)—to be the equivalent of 90% carbon capture and storage (CCS) or low-GHG hydrogen cofiring of 96% upon full implementation of the rule.
EPA promulgated in April 2024 its new source performance standards. The final rule is narrower than the proposed rule and leaves out the largest generation subsector—existing gas-fired combustion turbines (CTs)—to more “comprehensive” rulemaking in 2025 or later.
- The rule applies to new or reconstructed fossil-fired CTs, existing fossil-fired steam units, and modified coal-fired steam units (modifications causing >10% in hourly CO2 emissions).
- EPA has removed low-GHG hydrogen from its BSER, targeting the GHG emissions based upon CCS at a 90% capture rate (equivalent to an 88.4% CO2 reduction).
- The standard of performance is technology neutral. Although the standards are set by a BSER, sources may comply using other methods—for example, hydrogen cofiring.
- Baseload units have the most onerous emissions standards, and EPA has reduced the threshold operation for a baseload unit at a 40% capacity factor (versus 50% in the proposed rule).
KEY TAKEAWAYS
EPA has promulgated a suite of rules, including requiring an effective ~90% reduction in GHG emissions from existing coal-fired generators and new gas-fired combustion turbines.
The rule affects 169 GW of coal generation, which is about 14% of the nation’s generating capacity.
EPA did not speak to existing gas-fired generation, although operating gas CTs and CCs total about 418 GW.
Absent increased capacity additions, system operators are sounding the alarm.
The rule is being vigorously challenged; it is unclear whether its validity will be impaired by the Supreme Court’s “major questions” doctrine.
EPA has promulgated a suite of rules, including requiring an effective ~90% reduction in GHG emissions from existing coal-fired generators and new gas-fired combustion turbines.
The rule affects 169 GW of coal generation, which is about 14% of the nation’s generating capacity.
EPA did not speak to existing gas-fired generation, although operating gas CTs and CCs total about 418 GW.
Absent increased capacity additions, system operators are sounding the alarm.
The rule is being vigorously challenged; it is unclear whether its validity will be impaired by the Supreme Court’s “major questions” doctrine.
Existing Coal Steam Units: Remaining Life Distinction
The rule takes aim at coal-fired units in particular, mandating compliance by 2032.
- Those coal units deemed long term—i.e., operating past 2031—must meet an emissions threshold by 2023 based upon the 90% capture BSER described earlier.
- Those deemed medium term—i.e., operating past 2031 but committed to retiring before 2039—have an emissions target of the equivalent of cofiring (by heat input) 40% natural gas and a 16% reduction in emissions rate by 2030.
- Those units retiring by 2032 are exempt from the rule.
Figure 1.1: EPA GHG Emissions Rule: Existing Coal-Fired Steam Units
Sources: EPA; ScottMadden analysis
Existing Oil- and Gas-Fired Steam Units: Unit Duty Distinction
Existing oil- and gas-fired steam generators can employ “routine methods of operation and maintenance” with no increase in emissions rate as of 2030.
- Baseload units (oil and gas)—annual capacity factor >45%—can employ “routine methods” but must be less than 1,400 lbs. CO2/MWh-gross by 2030.
- Intermediate load units (oil and gas)—annual capacity factor ≥8% and ≤45%—have a slightly higher compliance threshold of 1,600 lbs. CO2/MWh-gross by 2030.
- Low load units—annual capacity factor <8%—require only the use of uniform fuels and have emissions limits, based upon heat input, of 130 lbs. CO2/MMBtu (for gas) and 170 lbs. CO2/MMBtu (for oil).
EPA determined that CCS as a BSER would capture relatively little CO2 in comparison to its capital and operating cost. It also noted there are relatively few units (200 gas-fired steam units and 30 oil-fired steam units) that mostly operate as load-following with relatively low capacity factors. Average annual cap factors for gas steam units were less than 15%, and no oil units operated above 8%.
New Combustion Turbines: 90% Carbon Capture BSER for Baseload Units
EPA has established emissions standards for any new CTs operating after May 23, 2023, the date of the proposed rules.
- Baseload units—annual capacity factor >40%—must operate at emissions levels equivalent to highly efficient combined-cycle generation (800-900 lbs. CO2/MWh, depending upon size) until 2032. Thereafter, new CTs must meet a 90% CCS standard effective 2032 or less than 100 lbs. CO2/MWh.
- Intermediate load units—annual capacity factor 20%-40%—must operate at emissions levels equivalent to highly efficient simple-cycle generation (1,170 lbs. CO2/MWh) upon start-up. There is no future, more stringent Phase II requirement.
- Low load units—annual capacity factor <20%—must use lower-emitting fuels and achieve emissions less than 160 lbs. CO2/MWh upon start-up. There is no future, more stringent Phase II requirement.
For new CTs, EPA’s final rule is more stringent than the proposed rule, as EPA lowered the threshold for “baseload” treatment, requiring much lower emissions, to >40% capacity factor from >50% as originally proposed.
Figure 1.2: EPA GHG Emissions Rule: New Fossil-Fired Combustion Turbines
Note: Targets referenced in text are for natural gas, which dominates new additions, but the standard noted in the ranges in Fig. 2.1 includes all fossil fuels, including oil.
Sources: EPA; ScottMadden analysis
No Action on Existing Gas-Fired Combustion Turbines
While the new GHG rules cover gas-fired steam units, they do not encompass existing gas-fired combustion turbines. However, EPA stated it is committed to “expeditiously proposing” GHG emission limits for these units. EPA Administrator Regan initiated in March 2024 a non-regulatory docket, with the goal of gathering input for a “stronger, more durable approach to greenhouse gas regulation of the entire fleet of existing gas combustion turbines.”
Timing of Implementation
The final rule changed the compliance timeline from its originally proposed rule in different ways for existing steam units and CTs:
- For new CTs, EPA moved up final compliance from 2035 to 2032 for baseload units.
- By contrast, for existing coal steam units, the compliance deadline was extended to 2032 from 2030.
Under either deadline, it is uncertain whether units can comply with a 90% CCS standard absent significant commercialization of the technology (see Figures 1.3 and 1.4) and deployment of takeaway CO2 pipeline capacity or nearby sequestration options, which are location specific.
Whither Hydrogen Cofiring?
EPA’s proposed 2023 rule proposed an additional BSER pathway for new CTs: low-GHG hydrogen cofiring of 96% (for units with capacity factors of ≥50%) or 30% (for units with capacity factors <50% and ≥20%). EPA eliminated this option in its final rule.
- Many critics of the proposed rule contended that clean hydrogen was not adequately demonstrated and that its cost as a compliance method was underestimated.
- DOE has subsequently studied clean hydrogen “pathways to commercial liftoff” and found that low-emissions hydrogen would be $1.15 per kilogram (equivalent to about $8.50/MMBtu of natural gas), compared to EPA’s assumed $0.50 per kilogram.
- Moreover, the U.S. National Clean Hydrogen Strategy does not envision nearly the volumes required under the proposed rule by the compliance deadline.
This feasibility and cost challenge may be an approach that opponents of the final rule employ.
Figure 1.3: Selected Operating and Planned U.S. Power Plants with CCS
Note: FEED means front-end engineering and design.
Sources: Global CCS Institute; Power magazine; Partners for Environmental Progress; Yale Climate Connections
Figure 1.4: Ranges of Carbon Capture and Storage Costs by Activity and IRS 45Q CCS Tax Credit Levels by CO2 End Use ($/Ton)
Costs shown do not reflect a 20%+ reduction in net power output for parasitic steam and power loads required for CO2 capture.
Notes: Values color-coded to show source. *Retrofits. CBO costs represented in 2019$; DOE costs not specified by “as of” year. EOR means enhanced oil recovery.
Sources: Congressional Budget Office; DOE
Challenges to the Proposed Rule
Upon release of the rule, 24 state attorneys general and other parties filed an unsuccessful emergency appeal to stay the rule. However, the D.C. Circuit federal appeals court ordered an expedited case with briefs submitted in September and October 2024.
- Opponents argue that CCS is not adequately demonstrated, and EPA did not show that all three elements—capture, transport, and sequestration—can be deployed by 2032 nor is 90% capture “achievable.”
- EPA points to several existing and proposed plants that have achieved or are designed to achieve high CO2 capture rates. It also argues that the rule is within its jurisdiction as the BSER applies only “inside the fence line” (although one might argue that required non-plant CCS infrastructure is not within the purview of the plant operator).
Unlike prior actions like the Clean Power Plan, there is to date no stay of the rule, which may lead to units closing sooner than later or make other irrevocable decisions, including decisions not to construct new gas-fired units. This may be exacerbated by EPA’s other, less discussed rulemakings affecting the sector (see Less Discussed section later). On October 16, the Supreme Court declined to stay the rule pending appeal.
Figure 1.5: EPA’s Assumed Coal-Fired Plants (as of 2039) Potentially Covered Under New GHG Emissions Standards (CPS) and Mercury and Air Toxic Standards (MATS) Updates
As of August 2024, there were 169 GW of conventional coal-fired generation net summer capacity.
When it released the GHG rule, EPA assumed that over the next 15 years, 103 GW of such capacity have announced plans to retire or convert to natural gas. Of the remainder, 36 GW will be more than 60 years old by 2039.
So, while technically “covered” under the rule, much more capacity will be “affected” by the rule.
Notes: Units retiring prior to 2032 are not subject to the CPS rule. The universe is likely smaller, as many plants do not announce retirement plans this far in advance.
Source: EPA
Reliability Concerns
Given the potential impact of the rule on both existing and prospective dispatchable thermal generation, utilities, system operators, and state regulators are concerned about potential reliability impacts of the rule.
EPA points to the two additional years given for coal-fired plant compliance (to 2032) over the proposed rule to provide more time to install CCS. It also points to other flexibilities in the rule:
- RULOF: Some allowance to reflect localized circumstances in state plans, taking into account Remaining Useful Life and Other Factors (RULOF), and allowing emissions trading and averaging in some situations.
- Compliance extension: Potential compliance extension of up to one year to sources installing control technologies if they experience unanticipated delays outside of the owner or operator’s control.
- Reliability mechanisms: The rule adds two optional, reliability-related mechanisms related to grid emergencies (short term) and those with retirement dates but a verified reliability need (see Figure 1.6).
Despite these mechanisms, some industry observers point to growing generator retirements (potentially exacerbated by the rule), growing energy demand, and the slow pace of additions (see Figures 1.7 and 1.8) with interconnection backlogs and constraints on materials and labor, despite reliability mechanisms.
Figure 1.6: EPA’s Two Optional Mechanisms to Support Reliability
Source: EPA
Figure 1.7: Projected Annual Net Summer Capacity Additions of Natural Gas-Fired Combustion Turbine and Combined-Cycle Units by Year and % Completion (MW)
Figure 1.8: Projected Annual Net Summer Capacity Retirements of Natural Gas-Fired Combustion Turbine, Natural Gas-Fired Combined Cycle, and Coal Units by Year (MW)
Note: Excludes facilities with a total nameplate capacity <1 MW.
Sources: EIA data (as of Aug. 2024); ScottMadden analysis
Less Discussed: Other EPA Rules Affecting Coal-Fired Generation
EPA’s Clean Air Act Section 111 GHG standards were issued at the same time as three other rules as part of a suite affecting all coal plants.
These EPA rules tighten and broaden regulation of non-GHG air emissions as well as water and solid waste pollutants. Those rules include the following:
- A final rule updating the Mercury and Air Toxics Standards for coal-fired power plants, tightening the emissions standard for toxic metals by 67% and finalizing a 70% reduction in the emissions standard for mercury from existing lignite-fired sources. The rule also reduces limits on particulate matter from 0.03 to 0.01 pounds per MMBtu. EPA’s analysis suggests that 5 GW of operational capacity will need to comply by 2028.
- A final rule to reduce pollutants discharged through wastewater from coal-fired power plants by more than 660 million pounds per year. The rule sets a zero-discharge standard for flue gas desulfurization wastewater. EPA estimates this will affect about 232 power plants.
- A final rule will require the management of coal ash that is placed in areas that were unregulated at the federal level until now, including at previously used disposal areas that may leak and contaminate groundwater. These rules affect inactive surface impoundments, and EPA does not expect the rule to affect current power plant operations.
IMPLICATIONS
Even before the EPA rule, coal-fired power plants have been retiring due to age and market forces, as well as increasing pressure from environmental regulation and some stakeholder segments seeking more rapid decarbonization.
The tightening of emissions standards on new gas-fired units and the hinted but unknown regulatory framework for existing gas units injects some uncertainty, particularly as the industry has been leaning on those units for dispatchability and flexibility.
System planners and operators must continue to prepare for alternative resource mixes over the long term and will need to seek creative solutions—energy storage, demand-side options, unit duty-cycle management (to avoid excursions that run afoul of the capacity factor-based structure)—to manage reliability and minimize operating costs.
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