4 The record articles

Delving into the Affordable Clean Energy Rule

Posted: December 19th, 2018

Authors: All4 Staff 

The Affordable Clean Energy (ACE) Rule was proposed by the U.S. EPA as a replacement to the Clean Power Plan (CPP) on August 21, 2018.  Regular readers of our 4 The Record articles will recall my past thoughts on what a replacement to the CPP might someday look like.  In this article we’ll explore the recent proposed ACE rule and its potentially far-reaching implications beyond the utility industry.  There’s a lot to cover, so let’s get right into it!

The rule proposal made its official appearance in the Federal Register on August 31, 2018.  It includes the following three distinct actions:

  • Emission Guidelines for Greenhouse Gas (GHG) Emissions and Compliance Times for Existing Electric Utility Generating Units (EGUs)
  • Revisions to the Emission Guidelines Implementing Regulations
  • Revisions to the New Source Review Program

Before reading any further than the title of the rule proposal, there are a few things that immediately jumped out at me:

  • Like the CPP, much of the ACE Rule proposal is focused on providing emission guidelines for states to utilize when establishing standards of performance in their State Plans.
  • The proposal includes revisions to the NSR program for EGUs.
  • The initial proposal applies to existing sources and does not include provisions for new, modified, or reconstructed units.

As we walk through the rule proposal, we’ll dig into these initial observations and several others.

Emission Guidelines for GHG Emissions and Compliance Times for Existing EGUs

As currently proposed, each state will have three years to develop a process (in the form of a State Plan) for establishing standards of performance that reflect application of the Best System of Emission Reduction (BSER) at each individual affected existing EGU.

At the onset, this sounds like it’s initially going to be a state’s problem, right?  While it’s true that each state will ultimately have responsibility for proposing their individual State Plans, EGUs should expect to have some involvement in the process.  States would likely set up a “framework” for operators to provide source-specific information to a state agency to inform their preparation of an appropriate state-specific Plan.  One of the key distinctions of the ACE Rule (as compared to the CPP) is that the states have a lead role and broad discretion in setting performance standards within their jurisdictions.  As an EGU, you likely feel relief knowing that your state can account for diversity in EGU operating characteristics and performance levels from source to source, and site to site.

If you’re interested in learning more about proposed State Plan requirements, I encourage you to review proposed 40 CFR §§60.5735a through 60.5765a in detail.  However, here are some of the highlights (as currently proposed):

  • An EGU meeting all the following criteria would be required to be included as an affected source within a State Plan:
    • Commenced construction on or before August 31, 2018.
    • Is a steam generating unit that serves a generator connected to a utility power distribution system with a nameplate capacity greater than 25-megawatt (MW) net (i.e., capable of selling greater than 25 MW electricity).
    • Has a baseload rating (i.e., design heat input capacity) greater than 260 gigajoules (GJ) per hour (hr) [i.e., 250 million British thermal units per hour (MMBtu/hr)] heat input of fossil fuel (either alone or in combination with any other fuel).
    • Is not any of the types of units described at proposed 40 CFR §60.5780a.
  • Each State Plan submittal would be required to include an applicability evaluation for each EGU regarding specific types of heat rate improvements (HRI) listed in the rule. As proposed, there are seven listed HRI types to consider, which include (but are not limited to) neural network/intelligent sootblowers, boiler feed pumps, and redesign or replacement of the economizer.

U.S. EPA is specifically proposing that BSER for GHG emissions from existing coal-fired EGUs is HRI that can be applied at the source, citing seven technologies as specific options.  There is a clear theme in this rule proposal on improving the performance of individual EGUs on a unit-by-unit basis, rather than achieving aggregate carbon dioxide (CO2) emissions reductions for the entire power sector at either a state or national level.

Although Carbon Capture and Sequestration (CCS) or mandatory co-firing with natural gas or biomass are currently excluded from the proposal, the revised provisions do not come without their set of own concerns, for example:

  • The success of employing multiple HRI projects is not necessarily additive.
  • HRIs are not permanent and can degrade over time.
  • The success of each HRI project (HRI potential measured as a percentage) is going to be extremely site-specific and can be expected to vary based upon operating conditions [e.g., the thermodynamic cycle of a given boiler, boiler/steam turbine size and design, cooling system type, auxiliary equipment (including air pollution controls), operation and maintenance practices, fuel quality, and ambient conditions].
  • Certain HRI listed as candidate technologies specifically improve an affected EGU’s net heat rate and would be detrimental to implementing if a standard of performance is finalized on a gross output basis.
  • Averaging times are left to the discretion of individual states and may not end up reflecting variable operation due to market demand over time or the fact that GHG emissions are acknowledged as having long- (rather than short-) term impact.
  • Emissions averaging and trading is currently limited to an “inside the fenceline” approach and doesn’t afford states the option to adopt broader compliance options and allow (for example) trading among affected units located at different facilities within the same state.

As currently proposed, if a state does not submit a Plan within three years of rule finalization (or the date that U.S. EPA disapproves a final State Plan), U.S. EPA would implement and enforce a Federal Plan that would be applicable to each affected EGU that commenced construction on or before January 8, 2014 within that state.  The specific compliance schedule that would apply to a particular EGU is left somewhat to the discretion of each state (unless a state does not submit its Plan by the applicable deadline – see above).  In the proposal, states are given flexibility in establishing schedules, except that a state would be required to include increments of progress to achieve compliance for any designated facility or category of facilities whose compliance schedule extends more than 24 months from the State Plan submittal deadline.

Revisions to Emission Guidelines Implementing Regulations

U.S. EPA has proposed revisions to the existing Emission Guideline Implementing Regulations at 40 CFR Part 60, Subpart Ba.  The provisions of new Subpart Ba would apply to states upon publication of a future emission guideline under 40 CFR §60.22a.  The intent of new Subpart Ba is to make it clear that states have broad discretion in establishing and applying emissions standards consistent with BSER, and to give states adequate time and flexibility to develop their State Plans.  As stated previously, under the proposal, a state would have three years to develop its State Plan, whereas it would have nine months under the existing implementing regulations.  Similarly, under the proposal, U.S. EPA would have 12 months to act on a complete State Plan submittal, whereas it would have four months under the existing implementing regulations.  The new Subpart Ba requirements are also the basis for U.S. EPA implementing and enforcing a Federal Plan within two years of a state failing to submit a complete State Plan, or within two years of U.S. EPA disapproving a State Plan.  Under the existing implementing regulations, the timeframe to implement a Federal Plan would be within six months of U.S. EPA’s finding of failure or disapproval.

Proposed Revisions to the New Source Review Program

The portions of the rule proposal that have the most far-reaching implications are those that propose revisions to the New Source Review program.   U.S. EPA has proposed these revisions at 40 CFR Parts 51 and 52 so that they are intentionally severable from the ACE Rule proposal at 40 CFR Part 60, Subpart UUUUa and the Implementing Regulations proposal at 40 CFR Part 60, Subpart Ba.

Under the current NSR regulations, a two-step analysis is performed to determine whether a proposed project is a “major modification.”  In short, the Step 1 analysis involves determining whether the project will cause a “significant emissions increase” of any regulated NSR pollutants.  Pursuant to 40 CFR §52.21(iv)(d), for a new unit, an “actual-to-potential” applicability test is used, where baseline actual emission (BAE) rates (pre-project) are subtracted from potential to emit (PTE) emission rates (post-project).  Per §52.21(48)(iii), BAE emissions from a new unit will equal zero; and thereafter, for all other purposes, equal the unit’s potential to emit.  Pursuant to 40 CFR §52.21(iv)(c), an “actual-to-projected-actual” applicability test is used for an existing emissions unit that is being modified, where the differences between BAE and projected actual emission (PAE) rates are evaluated.  Step 2 is triggered only if there is a “significant emissions increase” calculated during Step 1, and involves an evaluation of those increases along with any other emissions increases and decreases that have occurred during the contemporaneous period for the project.

Determining what is a “significant emissions increase” under the Step 1 analysis has been the subject of much policy debate since the introduction of the NSR Program.  We’ve tweaked our analyses over time (recall U.S. EPA’s recent memorandum clarifying that the Step 1 analysis shall account for both the emissions increases and decreases that may result from a proposed project).  But the proposed changes under the ACE Rule are a bit more dramatic.

Since the beginning of the NSR program, project-related significant and net significant emissions increases were based on an evaluation of annual emission rates.  U.S. EPA is now proposing a new preliminary applicability test for determination of whether a physical or operational change made to an EGU constitutes a “major modification.”  Specifically, U.S. EPA is proposing to give states the option to adopt an hourly emissions increase test (i.e., off-ramp), where projected hourly emissions would be compared to baseline hourly emissions, and the typical NSR review would not be required unless an hourly emissions increase is first calculated.  If finalized as proposed, the major NSR applicability test for existing EGUs would look like this:

  • Step 1 – Determine whether the project constitutes a physical change or change in the method of operation. If yes, proceed to Step 2.  If not, the applicability test is complete.
  • Step 2 – Perform an “hourly emissions increase test.” If an hourly emissions increase is calculated for the proposed project, proceed to Step 3.  If not, the applicability test is complete.
  • Step 3 – Evaluate whether a significant (annual) emissions increase will occur pursuant to the current NSR rules. If a significant emissions increase will occur, proceed to Step 4.
  • Step 4 – Evaluate whether a significant net emissions increase will occur pursuant to the current NSR rules. If a significant net emissions increase will occur, the project is a “major modification” and NSR applies.

Let’s take a closer look at the proposed Step 2 “hourly emissions increase test.”  U.S. EPA has proposed three separate alternatives (Alternatives) for conducting this new analysis.  Use of one alternative over another depends upon such things as the quality of an EGU’s historic data, how the EGU elects to calculate pre-change emissions, and whether the EGU prefers to represent pre-change hourly emissions of a “maximum achieved” vs. “maximum achievable” basis.

In a nutshell, the calculations are performed per the various Alternatives as follows:

  • Alternative 1

    • Pre-Change Emissions: Calculated using a statistical approach prescribed in the rule based upon actual “maximum achieved” emissions data.
    • Post-Change Emissions: Calculated by projecting the maximum emissions rate that the EGU will actually achieve in any one hour in the five years following the date the EGU resumes regular operation after the physical or operational change.
    • Required For: Each regulated NSR pollutant for which hourly average Continuous Emissions Monitoring System (CEMS) or Predictive Emissions Monitoring System (PEMS) data is available with corresponding fuel heat input data.
  • Alternative 2

    • Pre-Change Emissions: Calculated (using best available data) as the highest hourly emissions rate actually achieved by the EGU for one hour at any time during the five-year period immediately preceding the start of construction or making the operational change.
    • Post-Change Emissions: Calculated by projecting the maximum emissions rate that the EGU will actually achieve in any one hour in the five years following the date the EGU resumes regular operation after the physical or operational change.
  • Alternative 3

    • Pre-Change Emissions: Calculated as the “maximum achievable” hourly emissions rate before the physical or operational change per 40 CFR 60.14(b).
    • Post-Change Emissions: Calculated as the “maximum achievable” hourly emissions rate after the physical or operational change per 40 CFR 60.14(b).

Under any of the Alternatives, only projects that increase a plant’s hourly rate of pollutant emissions would need to undergo a full NSR analysis.  Regardless of the Alternative used in the applicability test, an emissions increase would occur if the hourly emissions rate actually achieved in the five years after the change ever exceeded the pre-change maximum actual hourly emissions rate.

Implications of the Proposed NSR Revisions

The proposed NSR reform provisions of the ACE rule are getting plenty of attention.  U.S. EPA’s written intent is to “give owners/operators of EGUs more latitude in making efficiency improvements that are consistent with U.S. EPA’s BSER without triggering onerous and costly NSR permit requirements.  This change will allow states, in establishing standards of performance, to consider HRIs that would otherwise not be cost-effective due to the burdens incurred from triggering NSR.”

The proposed NSR revisions are viewed by the EGU affected facilities and the regulated community in general, as a beneficial aspect of the ACE rule.  While the proposed changes to the NSR regulations are limited to EGUs, if finalized as proposed, history indicates that the revisions will eventually find their way to the regulated community at large.  Concerns have been voiced that the proposed test, in its lack of requiring an EGU to evaluate its annual emissions changes, is going to result in plants undergoing physical or operational changes that actually increase annual emissions, without requiring those plants to undergo NSR.  There are, of course, already legal challenges.  There are plenty of questions around precedent and when/how this could be extended beyond EGUs.  As proposed, the revised NSR test is an option for state programs, but when the rule is finalized could it actually be a mandatory NSR provision?  How will states implement such provisions in SIP approved programs?  Stay tuned in on this aspect of the ACE rule proposal.

To incorporate the four-step modification provisions, U.S. EPA has proposed to add two new sections to the major NSR program rules.  The first section, 40 CFR §51.167, would specify that State Implementation Plans (SIPs) may include a new Step 2 for major NSR applicability at existing EGUs, including those for both attainment and nonattainment areas.  The second section, 40 CFR §52.25, would specify the requirements for major NSR applicability for existing EGUs where U.S. EPA is the reviewing authority or U.S. EPA has delegated its authority to a state or local air permitting agency.

The new sections at 40 CFR §51.167 and §52.25 are proposed as separate and distinct from the other NSR provisions.  Keeping the provisions severable was intentional so that the separate NSR applicability requirements for Electric Utility Steam Generating Units (EUSGUs) and non-EUSGUs that are not EGUs are maintained.

What about New, Modified, and Reconstructed Sources?

A pre-publication version of a separate draft proposal that applies to new, modified, and reconstructed EGUs became available for review on December 6, 2018.   This second proposal is expected to be on a fast track to finalization.  Given the unlikelihood that new domestic coal plants are being planned [where “new source” is defined as any stationary source, the construction, modification, or reconstruction of which is commenced after the publication of proposed regulations prescribing a CAA section 111(b) standard], the real-world impact of this second proposed rule is expected to be small.  However, we are in the process of reviewing the details and will be sharing them with our readers in the coming weeks.  Stay tuned!


U.S. EPA accepted comments on the August 31, 2018 ACE Rule proposal through October 30, 2018 and held one public hearing.  We will continue to keep you updated on activity concerning the proposed ACE rule and its companion rule for new, modified, and reconstructed sources.  I’m curious to know, what do you think of the recent ACE Rule proposal?  Leave a comment below or contact us at info@all4inc.com.


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