Evolution of U.S. Environmental Protection Agency’s Regulation of Greenhouse Gas Emissions from the Power Sector

The final Affordable Clean Energy (ACE) Rule was promulgated in the Federal Register on July 8, 2019.  The Federal Register notice officially repeals the Clean Power Plan (CPP), replacing it with the ACE Rule, and represents quite a change in thinking by the U.S. Environmental Protection Agency (U.S. EPA).  Before providing a summary of the final rule and some thoughts on what’s next, I thought it would be interesting and informative to look back at the evolution of U.S. EPA regulation of greenhouse gas (GHG) emissions from the power sector as a reminder of how we have arrived at the current state of things.  It all started 20 years ago when several groups petitioned U.S. EPA to regulate GHG emissions from motor vehicles.  Many legal actions and 10 years passed before U.S. EPA issued a finding that GHG emissions endanger public health and welfare and motor vehicle emissions were contributing to air pollution (the so-called Endangerment Finding).  The Endangerment Finding paved the way for various GHG regulations affecting several industrial sectors.

New Source Review and Title V

Once U.S. EPA made the Endangerment Finding and CO₂ became a regulated pollutant, it needed to address the impacts on stationary source programs like New Source Review (NSR) and the Title V operating permit program.  U.S. EPA addressed both the timing of GHG regulation under these programs and the thresholds at which a source or modification would be major for GHG.  The April 2010 Timing Rule determined that the earliest GHG emissions could be regulated was January 2, 2011.  The “Tailoring Rule” finalized in May 2010 established a 100,000 ton per year (tpy) major source threshold and a 75,000 tpy significant emissions rate (SER).  GHG Permitting guidance documents and white papers were issued, and litigation ensued.  In 2014, the U.S. Supreme Court determined that U.S. EPA may not treat GHGs as an air pollutant for the purposes of determining whether a source is required to obtain a Prevention of Significant Deterioration (PSD) or Title V permit, but if a permit was otherwise required, GHGs could also be regulated if emissions were above the major source threshold or SER.  U.S. EPA proposed changes in 2016 to align their regulations with the court decision but has not finalized these changes yet.  The bottom line is that a project cannot trigger PSD review or the need for a Title V permit based on GHG emissions alone, but if other pollutants trigger PSD review, GHG emissions can undergo PSD review if they are above the SER.

Regulation of GHG Emissions from the Power Industry

The first power sector requirement (and general industry requirement) related to GHG emissions came in the form of the Mandatory Reporting Rule (MRR), finalized in 2009. This rule requires various industrial sectors to report GHG emissions to U.S. EPA electronically but does not include any emissions standards.  Some have commented that U.S. EPA should do away with the MRR now that it has 10 years of data, as part of the current administration’s initiative to reduce regulatory burden on industry.

Because the power sector is a large contributor to overall U.S. GHG emissions, U.S. EPA proceeded to develop regulations for both new and existing fossil fuel-fired power plants.  These regulations were initially proposed and finalized under the Obama administration but have evolved under the current administration.  All of U.S. EPA’s GHG regulatory proposals were controversial and resulted in millions of public comments.  A summary of U.S. EPA’s regulatory actions is provided below.

• U.S. EPA proposed the first GHG standards for new fossil fuel-fired power plants in April 2012. U.S. EPA proposed to apply the standards to coal and natural gas-fired electric generating units (EGU).  Because U.S. EPA believed that no new coal-fired power plants would be built, it based the standards on the best performing natural gas combined cycle (NGCC) units and proposed to require all new fossil fuel EGUs to meet an output-based standard of 1,000 pounds of carbon dioxide per megawatt hour (lb CO₂/MWh).
• In 2013, President Obama issued his Climate Action Plan and directed U.S. EPA to develop standards not only for new power plants, but also for modified, reconstructed, and existing power plants.
• In response, U.S. EPA withdrew the 2012 proposed standards of performance for new stationary sources (NSPS) and re-proposed standards for new fossil fuel fired EGUs in late 2013 that were published in the Federal Register in January 2014. That proposal included separate limits for new EGUs firing fossil fuels other than natural gas and also included different limits based on the size of each type of unit.  The proposed limits for non-gas fired EGUs were based on partial carbon capture and storage (CCS).  Many stakeholders felt that it was not appropriate to base limits on a technology that was not fully proven.
• Later in 2014, U.S. EPA proposed standards for modified and reconstructed fossil fuel fired EGUs and also proposed the Clean Power Plan (CPP, formally titled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”), which outlined how states were to develop plans to regulate CO₂ emissions from existing fossil fuel-fired EGUs.
• In October 2015, U.S. EPA finalized standards for new, modified, and reconstructed fossil fuel fired EGUs at 40 CFR Part 60, Subpart TTTT. Subpart TTTT contains different limits for GHG emissions from steam generating units, integrated gasification combined cycle (IGCC) units, or stationary combustion turbines that commence construction after January 8, 2014 or commence modification or reconstruction after June 18, 2014.  The limits for coal-fired boilers are higher than those originally proposed and there is more than one limit for gas turbines, depending on fuel fired and mode of operation.  (Note that U.S. EPA proposed to further revise Subpart TTTT in December 2018 but has not finalized that proposal.)
• Also in October 2015, U.S. EPA finalized the CPP requirements for existing fossil fuel fired EGUs at 40 CFR Part 60, Subpart UUUU. Subpart UUUU included a multifaceted approach to reducing GHG emissions from existing fossil fuel fired EGUs that many contended was beyond the scope of U.S. EPA’s regulatory authority.  U.S. EPA set goals for states to achieve by not only requiring inside the fenceline improvements in heat rate and efficiency of existing coal-fired power plants, but also by requiring increased use of NGCC units and zero-emitting renewable energy sources, and decreased use of coal-fired power plants (preferential dispatch of lower-carbon power to the electric grid).  Each state had a different goal based on its particular mix of EGUs.
• In 2016, the CPP was stayed by the U.S. Supreme Court and did not go into effect.
• In March 2017, President Trump issued the Presidential Executive Order on Promoting Energy Independence and Economic Growth directing U.S. EPA to suspend, revise, or rescind various regulations intended to regulate GHG emissions from power plants, including, but not limited to, the CPP.

So – where are we now?

The Affordable Clean Energy (ACE) Rule

The ACE rule was proposed in August 2018 and finalized in July 2019 to repeal and replace the CPP with a new 40 CFR Part 60, Subpart UUUUa.  U.S. EPA has published a helpful table that summarizes the differences between the CPP and the ACE Rule.  The major differences and components of the ACE Rule are described below.

The ACE rule preamble states that U.S. EPA determined that it should repeal the CPP because the rule exceeded U.S. EPA’s statutory authority under the Clean Air Act (CAA).  The ACE rule has a fairly limited scope when compared to the CPP, in terms of both the affected facility and the applicable requirements.  The affected facility subject to the final ACE rule is any coal-fired electric utility steam generating unit that: (1) is not an IGCC unit (i.e., utility boilers, but not IGCC units); (2) was in operation or had commenced construction on or before January 8, 2014; (3) serves a generator capable of selling greater than 25 megawatts (MW) to a utility power distribution system; and (4) has a base load rating greater than 260 gigajoules per hour (GJ/h) (250 million British thermal units per hour [MMBtu/hr]) heat input of coal fuel (either alone or in combination with any other fuel).  U.S. EPA has determined that the best system of emissions reduction (BSER) for GHG emissions from coal-fired power plants is heat rate improvements¹, in the form of a specific set of technologies and operating and maintenance practices that can be applied at and to certain existing coal-fired EGUs.  Gone are the beyond-the-fenceline requirements to preferentially dispatch low- and zero-carbon power to the grid.  U.S. EPA also states that reduced utilization, co-firing natural gas, co-firing biomass, and CCS are not BSER for coal-fired power plants.

The ACE rule includes the following list of “broadly applicable” candidate technologies that should be evaluated as part of the strategy to improve heat rate at each affected facility, and states will establish unit-specific standards of performance that reflect the emissions limitation that the selected technologies will achieve.

• Neural Network/Intelligent Sootblowers
• Boiler Feed Pumps
• Air Heater and Duct Leakage Control
• Variable Frequency Drives
• Steam Turbine Blade Path Upgrade
• Redesign/Replace Economizer
• Improved Operating and Maintenance Practices

States can consider the remaining useful life of the unit and other source-specific factors in establishing the standards of performance, and will submit plans to U.S. EPA for approval.  The plans are due in 3 years.  If states do not submit plans or if U.S. EPA does not approve a state plan, U.S. EPA will impose a Federal Implementation Plan (FIP) within 2 years.

The final ACE rule preamble also sets out U.S. EPA’s current opinion on the roles of U.S. EPA, states, and sources when developing emission guidelines, not only for GHG emissions from power plants, but any future emission guidelines that U.S. EPA develops.  Specifically, U.S. EPA identifies BSER; states establish standards of performance for existing sources within their jurisdiction consistent with that BSER and also with the flexibility to consider source-specific factors, including remaining useful life; and sources then meet those standards using the technologies or techniques they believe are most appropriate.

U.S. EPA also sets out their arguments on why BSER must be applicable to, at, and on the premises of an affected facility.  The ACE rule preamble states that CAA Section 111 does not authorize U.S. EPA to select as BSER a system that is premised on application to the source category as a whole or to entities outside the regulated source category.  BSER cannot be premised on a system of emission reduction that is implementable only through the combined activities of sources or non-sources. U.S. EPA is precluded from basing BSER on strategies like generation shifting and corresponding emissions offsets because these types of systems cannot be put into use at the regulated building, structure, facility, or installation.  Interestingly, part of U.S. EPA’s argument that the scope of BSER is limited to the source itself relates to how best available control technology (BACT) analyses are performed.  It is U.S. EPA’s long-standing interpretation that BACT is limited to control options that can be applied to the source itself and does not include control options that go beyond the source.  Because NSPS is a “floor” to BACT (BACT limits are not to be less stringent than applicable NSPS limits), CAA Section 111 and BSER “cannot be interpreted to offer a broader set of tools” than are available for BACT.  U.S. EPA even goes as far as to state “for nearly 45 years prior to the CPP, this Agency had never understood CAA section 111 to confer upon it the implicit power to restructure the utility industry through generation-shifting measures.”  It remains to be seen if this interpretation will hold up in court and be a permanent guideline for how U.S. EPA moves forward with these types of rules.

One significant item that U.S. EPA proposed but did not finalize involves new source review (NSR) applicability to modifications power plants may make to comply with the ACE rule.  U.S. EPA had proposed that an hourly, not annual, emissions test would apply in this narrow circumstance, but did not finalize the NSR related provisions.  U.S. EPA indicates that they intend to take final action on that proposed change in a separate action on a later date.  If proposed changes are finalized, most ACE rule compliance projects would likely be exempt from NSR, unless accompanied by a capacity increase or a fuel switch that increases maximum hourly emissions.

Petitions for review have already been filed by multiple groups, so we will have to wait and see whether the final ACE rule and U.S. EPA’s interpretation of its authority under CAA Section 111 stands.  Environmental groups are concerned that the final rule is not as stringent as the CPP, is too narrow in its application, and sets no numeric standards.  Some groups believe that the rule will result in increased GHG emissions because coal-fired power plants will run more often and delay retirement, especially if ACE rule compliance projects become exempt from NSR in a future regulatory action.  Industry groups believe that the ACE rule will not result in the increases in cost of electricity that they projected with the CPP.  Lawsuits will likely target U.S. EPA’s basis for repealing the CPP and its selection of BSER.  We never got a determination on whether the CPP was legal, since the litigation was held in abeyance while U.S. EPA reconsidered the CPP and developed the ACE rule, and there is no way to know if the court will determine that the ACE rule is a better approach than the CPP.

U.S. EPA projects that, compared to a no-CPP baseline, the ACE rule will reduce CO₂ emissions in 2030 by about 11 million tons, and that when combined with emissions reductions expected from the power industry’s current trend away from coal-fired generation, CO₂ emissions from the electric power sector will be reduced by as much as 35 percent below 2005 levels in 2030.  This level of emission reduction was the stated goal of the CPP, but it is speculated that much of the reduction is likely to occur in the absence of either CPP or ACE.

What’s Next and What Should I Be Doing?

Owners and operators of coal-fired power plants should be preparing to interact with state agencies as they work on their state plans.  Rather than rely on the state to develop requirements, facilities should determine what units are affected, document what HRI actions have already been taken, and analyze what HRI projects can feasibly be performed on a unit-specific basis.  It is not clear what the actual impact of the rule will be because U.S. EPA declined to mandate specific numeric limits or work practice standards.  It is conceivable that the newest, most efficient units may not have any upgrades to make and the oldest units will not be forced to make any upgrades if they are nearing retirement.  Industry groups have noted that they think the ACE Rule will have much less of an impact on the cost of electricity than the CPP would have.  Facilities implementing projects will need to determine if air permit modifications are required prior to performing the projects, and whether these projects will trigger state control technology analysis or modeling requirements.  The power sector should also keep an eye on the status of the litigation surrounding GHG regulations and the ACE rule to watch for any changes to applicability or requirements.  In addition, the final revisions to NSPS Subpart TTTT and to the permitting rules are still outstanding, and those rules have broader applicability than just the power sector.  Stay tuned for future updates on the continuing evolution of GHG regulations and contact your ALL4 project manager or Amy Marshall (amarshall@all4inc.com or 919.777.3073) with any questions.

¹The heat rate is the amount of energy or fuel heat input (typically measured in British thermal units, Btu) required to generate a unit of electricity (typically measured in kilowatt-hours, kWh). The lower an EGU’s heat rate, the more efficiently it converts heat input to electrical output. As a result, an EGU with a lower heat rate consumes less fuel per kWh of electricity generated and, as a result, emits lower amounts of CO₂ – and other air pollutants – per kWh generated.