A Year in Review – New Source Review (NSR) Edition

It’s been a long and winding road for New Source Review (NSR) regulation, both since the dawn of [NSR] time and over the course of 2018 alone, where a litany of NSR reform guidance memos were released by U.S. Environmental Protection Agency (U.S. EPA).  So, what do you say we hop in the ALL4 Way-back Machine and review all of the NSR reform movement that’s taken place over the last year.

Let’s start our journey back in December 2017.  Former U.S. EPA Administrator Scott Pruitt released an NSR policy memo titled “New Source Review Preconstruction Permitting Requirements: Enforceability and Use of the Actual-to-Projected-Actual Applicability Test in Determining Major Modification Applicability” that addressed U.S. EPA’s interpretation of projected actual emissions (PAE) estimates for projects at major sources.  The purpose of the memo was for U.S. EPA to provide clarity on estimating PAE through “plain readings” of the existing NSR rules.  One of the main things that this memo discussed was whether a facility can factor in the intent to “actively manage future emissions” into a project projection.  U.S. EPA decided that those intentions are considered to be a part of “all relevant information” which is to be included per the as-written NSR rules; therefore, if a facility was planning on managing future emissions from a project specifically to avoid major NSR, then those should represent the projected emissions. However, as Colin McCall discussed following a House of Representatives hearing meeting he attended following the release of this memo, the U.S. EPA policy memo was inaccurately portrayed as providing facilities with a shield from NSR enforcement.  The one thing that was clear following the release of this memo and the House of Representatives hearing is that additional guidance was needed.

We’ve now landed in March 2018 and Administrator Pruitt has just released another NSR policy memo titled “Project Emissions Accounting Under the New Source Review Preconstruction Permitting Program”.  As ALL4’s Nick Leone and John Slade discussed in their respective articles, “New Source Review Project Emissions Accounting Guidance Memorandum” and “Project Emissions Accounting Under New Source Review Permitting”, this memo represented a significant policy change.  The March 2018 memo effectively changed a 2006 U.S. EPA policy of only accounting for emissions increases during “Step 1” of the typical “two-step” NSR applicability evaluation by now allowing facilities to account for emissions decreases that are associated with a given project during Step 1 of the analysis.  Although it may seem like a minor change, it has major real-world impacts.  A common example is the replacement of an old, high-emitting boiler with a new, lower-emitting boiler.  Under the new policy, the emissions decreases from the old boiler being replaced can be subtracted from the potential to emit (PTE) of the new boiler being installed, thereby increasing the likelihood that the calculated Step 1 emissions changes would not exceed NSR significant emissions increase thresholds.  Under the previous policy, only the PTE of new boiler could be considered under Step 1, greatly increasing the likelihood that Step 2 netting would be required and allowing for other unrelated emissions increases to be pulled into the evaluation, possibly changing the NSR outcome when compared to the new policy.

One of the other major changes in this memo was the allowance that emissions decreases that are part of the project and included in the Step 1 evaluation do not need to be federally enforceable (i.e., emissions decreases could now be reflected in the sum of the PAE associated with a modification project and only those emissions decreases that are evaluated under step two netting must be enforceable under the new guidance).  This policy change, if uniformly implemented by state and local permitting authorities, will impact applicability, impact calculations, and ultimately major NSR applicability to many projects involving “affected” emissions units.

There was a lot to unpack in the March 2018 memo and I highly recommend reading Nick and John’s articles for more examples and discussion.  Please also note that this memo serves as guidance and not published rule.  Decisions are still left at the discretion of the permitting body.

Now let’s head over to September 2018.  U.S. EPA Assistant Administrator William Wehrum released a draft NSR policy memo for public comment titled “Interpreting ‘Adjacent’ for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas”.  The purpose of this memo was to provide clarity to both industry and agency officials regarding the term “adjacent” and how that affects the scope and extent of a “stationary source” when talking about major NSR and Title V permitting.  Upon the development of the NSR program in 1980, U.S. EPA focused exclusively on facility proximity when determining adjacency.  If two facilities were under common control, belonged to the same SIC Code, and were within a certain proximity, then that would qualify them as adjacent and therefore, qualify them as a single stationary source (i.e., one facility for permitting purposes).  However, more recently, U.S. EPA has not only considered proximity, but also the functional relationship or interrelatedness (e.g., if one facility shut down could the other still operate).  The September 2018 memo clarified that the original intent of the rule, and what U.S. EPA currently believes, was to only consider facility proximity in the adjacency determinations.  Note that proximity is still not explicitly defined and is still based on “common sense notion of a plant”.  Again, this memo serves as guidance and not published rule.

The last stop on our journey is November 2018.  U.S. EPA Acting Administrator Andrew Wheeler released a pre-publication version of a final action titled “Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR): Aggregation; Reconsideration”.  The purpose of this final action is to retract a previously proposed revocation of a January 2009 action on PSD and NNSR aggregation.  The January 2009 action was in regard to treating related physical or operational changes as a single “modification” for the purpose of determining NSR applicability.  This action required sources to aggregate emissions from nominally separate activities when they were “substantially related” for the purpose of determining whether they are a single modification resulting in an NSR emissions increase under “Step 1”.  The January 2009 action stated that in order to be substantially related, there needed to be either an apparent connection (either technically or economically) between the physical or operational changes or a complementary relationship, whereby a change at a facility may exist and operate independently, however its benefit is significantly reduced without the other activity.

This action was proposed to be revoked in April 2010; however, this November 2018 final action retracts that.  The idea of project aggregation is extremely important and ties into the March 2018 memo on project emissions accounting.  When thinking about the two-step process for tracking emissions increases and decreases at a source for a project, you have to make sure that the project is accurately defined.  By keeping the action requiring related physical or operational changes as a single modification (i.e., project), this eliminates the potential for a source to essentially break up a large, high-emitting project into multiple small, lower-emitting projects to avoid triggering major NSR requirements.  This project aggregation action ensures that nominally separate projects are treated as a single project where it is “otherwise unreasonable”.  As with most other aspects of NSR, “project” is not clearly defined and again, this is a case-by-case decision.

So that brings us back to present day.  Where do we go from here? What we do know is that U.S. EPA will likely continue to move in the direction of NSR reform and that there are a few more anticipated guidance memos in the works, including one on the definition of ambient air and on Plantwide Applicability Limits (PALs).  In the meantime, stay tuned for Roy Rakiewicz’s 2019 NSR Look Ahead article coming January 2019!

Thoughts or questions? Leave a comment below or contact me at kturney@all4inc.com or 610.933.5246 x143.

Delving into the Affordable Clean Energy Rule

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!

Closing

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.

Amendments to the Guideline on Air Quality Models, Where Are We Now and Other Recent Updates

We’ve been living with the amendments to 40 CFR Part 51 Appendix W – Guideline on Air Quality Models (The Guideline) for a little over a year and a half now so I thought it would be a good time to update the regulated community on how the changes have affected modeling projects that ALL4 has been involved with over the last year and a half.  The Guideline amendments went into effect after a “presidential-requested” delay on May 22, 2017, followed by a 1-year grace period to utilize pre-amendment guidance (if desired) which is now also over.  A side note for those involved with transportation conformity projects; the grace period continues for 3-years until May 22, 2020.

Most of the Guideline amendments either streamlined air quality modeling and/or allowed for the use of less conservative more accurate air quality modeling approaches.  I’d rank the advantages with respect to air quality modeling for permitting of the Guideline amendments as follows:

1. Nitrogen dioxide (NO₂) Tier 2 (i.e., ambient ratio method) and Tier 3 [i.e., ozone limiting method (OLM) and plume volume molar ratio (PVMRM)] options becoming default options.
2. Use of actual emissions rates when modeling local sources as part of National Ambient Air Quality Standards (NAAQS) demonstrations.
3. Modeled Emissions Rates for Precursors (MERPs) Guidance.

Tier 2 and 3 NO_X to NO₂ Conversion Options

Due to the stringent 1-hour NO₂ NAAQS, it has become a necessity to use less conservative, more accurate approaches for quantifying the conversion of oxides of nitrogen (NO_X) to NO₂ in the atmosphere.  The Tier 2 and Tier 3 options do this by incorporating measured amounts of ozone (O₃) to quantify this conversion.  The Tier 1 method of assuming that all NO_X emitted converts to NO₂ is overly conservative.  The Guideline amendment streamlined the process by incorporating the Tier 2 and Tier 3 methods as default options in AERMOD.  Before the Guideline amendments, the Tier 2 and 3 methods where non-default, which required alternative model review approval by both the state and regional EPA jurisdiction. The additional review and approval steps often slowed down the permitting process.

While these options are now default, the Guideline amendments established a default Tier 2 minimum ambient ratio (AR) of 0.5 and a Tier 3 NO₂/NO_X in-stack ratio (ISR) of 0.5 which are still conservative.  I’ve been preaching this to clients my entire career and will continue to recommend documenting ISR information during any stack test and/or as part of a continuous emissions monitoring system (CEMS).  For fossil fuel combustion sources, I typically see NO₂/NO_X ISR of 0.1.  Having ISR documentation of your emissions sources and/or similar emissions sources is the easiest way to justify the use of a lower than default AR or ISR which can make a substantial impact during your next construction permit application that could include air quality modeling requirements.  This may not be practical for all your emissions sources depending on your permit requirements.  Where actual ISR values are unavailable, the next best thing is to utilize documented ISR from similar sources.  However, it has been my experience that your local permitting jurisdiction may add a level of conservativism to this value that will fall between the measured ISR and the default ISR.  Be aware the U.S. EPA has an ISR database, though, not too many types of emissions sources have been certified since its inception (it’s mostly emergency generators that are included in the list).

Use of Actual Emissions

It has been my recent (18 months) experience that the use of local source actual emissions instead of potential-to-emit (PTE) emissions when conducting particulate matter less than 2.5 microns (PM_2.5), sulfur dioxide (SO₂), and NO₂ NAAQS modeling demonstrations has removed a level of significant conservatism.  This is particularly true, when conducting a cumulative impact NAAQS analysis as part of the Prevention of Significant Deterioration (PSD) permitting requirements, where applicants are required to include their facility emissions sources, local facility emissions sources, and background concentrations from representative ambient monitoring stations.  The Guideline amendments allow for the use of the average actual emissions from the two most recent years of operation (if the two most recent years are representative of normal operation) when modeling local sources as part of a NAAQS demonstration.  This approach is typically less conservative than the use of PTE emissions.  In addition, because of yearly state required emissions reporting, development of a local source emissions inventory can be a simpler process for those states that publish facility emissions reports online.

MERPs for ozone and secondary PM_2.5

As outlined in my recent blog post, the U.S. Environmental Protection Agency (U.S. EPA) Office of Air Quality Planning and Standards (OAQPS) finalized guidance which updated the PM_2.5 significant impact levels (SILs) and proposed a SIL for O₃.  One of the additions to the Guideline amendments is a new requirement to evaluate O₃ precursors, NO_X and volatile organic compounds (VOC).  In preparation for the Guideline amendments and the O₃ SIL, U.S. EPA released guidance in December 2016 outlining a screening approach for evaluating O₃ and secondary PM_2.5 precursors impacts through the development of modeled emissions rates for precursors (MERPs).  While the MERPs guidance was not part of the Guideline amendments, U.S. EPA did plan well by providing a screening approach to evaluate O₃ and PM_2.5 precursor which was part of the new Guideline amendments.

It has been my experience that use of the MERPs screening approach has been a straightforward streamlined approach to evaluate O₃ and secondary PM_2.5 precursors.  Essentially the MERPs are regionally based (e.g., eastern, central, and western) de-minimis emissions thresholds that are used to demonstrate that a project’s emissions won’t exceed the O₃ or PM_2.5 SILs and therefore, not adversely affect air quality and the need to conduct a quantitative O₃ or PM_2.5 precursor NAAQS analysis.  Be aware that some states have developed state specific MERPs (Georgia is the best example) based on conducting photochemical modeling for facilities in their state.

The Guideline amendments were generally favorable for permit applicants from the perspective of providing less conservative default options and more streamlined air quality dispersion modeling approaches.  However, air quality modeling remains a cumbersome process that continues to rely on inherently conservative guidance and approaches.  You might be asking if there will be more Guideline amendments soon to incorporate the current “state of the science.”  To answer that I’d point to the last time the Guideline amendments were made in 2005 as an indicator that it will likely be some time until another round of amendments is made.  That being said U.S. EPA OAQPS modeling staff have released a series of white papers prioritizing the planned areas of science updates to the AERMOD modeling system. They include:

1. LOWWIND Options
2. NO₂ Modeling Techniques
3. Downwash Algorithms
4. Mobile Source Modeling
5. Overwater Modeling
6. Saturated Plumes

White papers have been released for stakeholders to participate in improvements that would be expected to be proposed during the next Conference on Air Quality Models (Conference).  The Conference, held by U.S. EPA, is a unique requirement specified in the Guideline that must take place every three years, and is included as part of the process for making amendments to the Guideline.  Based on communication from U.S. EPA, the 12^th Conference on Air Quality Modeling is likely to occur in spring of 2019 at U.S. EPA OAQPS headquarters in RTP, NC.

If there is a project that your facility was considering before the Guideline amendments that was sidelined because of air quality modeling or not evaluated because of air quality modeling concerns, I’d recommend revisiting it because the Guideline amendments may positively impact the issues associated with your project.  Also, if any of the White Paper topics have been issues for your facility, consider engaging ALL4 to assist in proposing updates that could be incorporated in the next round of Appendix W amendments.

Mandatory Electronic Submittals of PA AIMS Reports in 2019

Major stationary air emissions facilities, and minor stationary air emissions facilities when requested, that are located in Pennsylvania, must submit an Annual Emissions Statement (AES) to the Pennsylvania Department of Environmental Protection (PADEP) by March 1 of each year for the previous calendar year.  This report is commonly referred to as the Air Information Management System (AIMS) report.  Facilities historically had the option of submitting the report by completing paper copies of AES forms, or by submitting the report electronically through PADEP’s AES Online or AES XML web portals.  As published in the June 17, 2017 issue of the Pennsylvania Bulletin, starting with the 2018 reporting year paper submissions of the AIMS report will no longer be accepted.

If you have previously submitted electronically via one of PADEP’s online portals, you know that the system can slow down considerably as more users attempt to enter data as the reporting deadline approaches.  Only time will tell, but one may assume that this issue may be exacerbated with the increased traffic that will be created by the additional users being required to submit electronically.  Plan ahead and consider entering data early in the morning or late in the day when traffic may be lower, and don’t wait until the last minute!

If you have never entered your AES online in the past, you’ll want to make sure you have a user name and password for PADEP’s GreenPort system.  Keep in mind, the certifying official for the facility must have their own account and be designated in GreenPort to allow for submission.  The preparer of the report (if different from the certifying official), would need their own GreenPort account.  If you don’t already have GreenPort access, you can either create an account by visiting the GreenPort page, or by completing the request form.  Once you have access, you should review the air emissions sources that are listed by PADEP to confirm the information contained online accurately reflects the air emissions sources at your facility.  If corrections are needed, reach out to your regional PADEP air inspector.

According to PADEP’s website the AES online system is currently offline and will re-open on December 26, 2018.  Be sure to connect soon after that date so that any issues can be resolved well before crunch time. However, this does not preclude a facility from setting up a PADEP account in GreenPort and confirming that the information for the air emissions inventory preparer and certifying official are correct for your facility.

ALL4 has extensive experience completing AES submissions, both electronically and using the now-antiquated paper copies  If you need help transitioning to the electronic reporting, please reach out to me at rkuklentz@all4inc.com or 610-933-5246×124.

U.S. EPA Releases Draft Guidance on “Ambient Air”

If you howl at the moon long enough, eventually you will capture someone’s attention.  When you are trying to get the attention of others to cause change, you might find the length of howling and the volume of your howl to be longer and louder than usual.  ALL4 has been publicly howling about how ambient air is defined since 2014 and was part of a stakeholder group that presented the issue to U.S. EPA in the fall of 2014.   But it appears that howling about how ambient air is defined has finally been noticed and U.S. EPA has issued draft guidance for assessing ambient air (public comments are being accepted until December 21, 2018).

Historically, U.S. EPA has defined ambient air as air external to a building and air to which access by the general public is not prohibited by a fence or physical barrier.  A determination of where ambient air begins is important when facilities must provide demonstrations [e.g., New Source Review (NSR) permitting, Title V permit renewal, state-only air permitting] that their air emissions do not result in concentrations that exceed a National Ambient Air Quality Standard (NAAQS) through air quality modeling.  Normally, the air quality modeling studies that are used for NAAQS demonstrations calculate the highest concentrations close to the emissions release point and lower concentrations at locations farther downwind.  Thus, if a facility is able to demonstrate that ambient air begins at greater downwind distances, lower air quality modeled concentrations are likely to result.  As the NAAQS have been established at lower concentration levels and shorter time intervals (i.e., 1-hour), the air quality modeling results for ambient air locations are more critical than ever.

So what has U.S. EPA done after listening to stakeholders?  Well most importantly, they have acknowledged that technology can play a role in defining areas to which the public is restricted.  U.S. EPA identified security cameras, drones, and future technologies as an equivalent to physical barriers or fences as measures to restrict the general public’s access from areas that are owned or controlled by a facility.  U.S. EPA also recommends that consideration of the facility location, size, and type, the local land use setting (i.e., rural, urban, nature and size of population), and other factors that might be related to public accessibility be evaluated in defining the extent of ambient air.

For some facilities that have distinctly defined and fenced property boundaries, low emissions, and well dispersed stacks, the guidance to interpret how ambient air is defined will have little benefit.  However, there are many, many facilities for which U.S. EPA’s guidance will provide relief from an antiquated assessment of how ambient air is determined.  If your facility has a project that is being held up due to air quality modeling concerns at ambient air locations, contact us to discuss how U.S. EPA’s revised ambient air guidance may offer relief to you.

What’s the next issue that we’ll start howling about?   Well, we’ve often wondered if a bias exists in the development of the NAAQS because of the focus on “sensitive” populations whose exposure responses to pollutant concentration levels serve as an important basis for developing the NAAQS.  If health conditions such as obesity or diabetes are more prevalent and result in lower pollutant concentrations thresholds causing health effects, is the real solution to protecting public health lowering air concentration levels?  Or instead of focusing on lower and lower pollutant concentration levels, should possible underlying health conditions be addressed?  Perhaps an approach to developing the NAAQS that looks equally at all parts of the general public instead of biasing the NAAQS for sensitive populations should be investigated.  Almost 50 years of air quality legislation and regulation have cleaned the air dramatically, but has a point been reached where we may need to consider new methodologies for assessing what concentration levels protect the health and welfare of the general public?  If you have any questions or want to discuss air quality modeling, I can be reached at ddix@all4inc.com or 610-933-5246 x118.