How Consistent Is Your Emissions Data?

This article is available as a podcast episode on ALL4’s Air Quality Insider

With greater frequency lately, many facilities are receiving inquiries from U.S. EPA regarding inconsistencies related to Federal Toxic Release Inventory (TRI) reporting and other regulatory reporting programs.  These inquiries tend to be in the form of an email, which can look something like this:

Dear TRI Facility Technical Contact:

This email message is part of EPA’s annual data quality check. EPA performs many analyses on the TRI data to ensure that the TRI dataset is of the highest quality possible. At this time we are reviewing the data for reporting years 2014-2016. A Form R from your facility’s [reporting year] submission(s) has been identified for follow-up due to the following:

The email then goes on to identify one or more specific discrepancies between emissions data reported to a state/local/tribal government compared to emissions data reported for TRI.  The email concludes with something like the following:

This inquiry does not automatically mean that EPA believes your facility has made an error. EPA would like to provide you with an opportunity to double check your submissions and, if necessary, make corrections. Please let us know if the data is correct as reported, will be revised or withdrawn.  We would appreciate your response back to me no later than [approximately 30 days later].

As U.S. EPA implies, there may be a legitimate reason for a discrepancy.  However, if an error is identified, U.S. EPA directs the recipient to TRI-MEweb, which is used to submit, revise, or withdraw TRI reporting forms.  While this example pertains specifically to TRI, we have seen inquiries across various state and Federal programs, and they appear to be automated due to the availability of electronic data.  We have also seen other similar inquiries before, especially for National Emissions Inventory (NEI) years like 2017  (i.e., every three years).

There are plenty of reasons why your state emissions inventory data may differ from the data reported for TRI purposes.  The TRI program addresses several types of releases from a facility (e.g., air, water, and waste) while state emissions inventory data focuses on air emissions.  Some substances may be reportable under one program and not another.  If there really is an error, a common reason we see is due to discrepancies between an emissions factor or calculation methodology across various programs.  Such discrepancies may occur because each report was prepared by a different individual at the facility, or because an emissions factor was updated for one program and not the other, or just because “it’s always been done that way.”

Emissions factors can change fairly frequently, especially if they are based on site-specific data; but published emissions factors (e.g., from AP-42, WebFIRE, or from trade organizations), may also change as new data becomes available.  How often does your facility review and update emissions factors, and how often are they updated consistently between reporting programs?

If you determine that a discrepancy identified by U.S. EPA requires a revision to the emissions data in the state or TRI report, where else was that emissions data used?  Having a procedure in place to ensure emissions data are representative and consistent across multiple programs becomes more important as electronic reporting and associated “data transparency” becomes more common.  Electronic emissions data are more accessible to regulators and the public for review, comparison, and scrutiny, and therefore facilities need to be confident in their emissions data.  Confidence can come from being proactive with your emissions data rather than reactive to inquiries.

With many different reporting obligations, could your facility use more consistency?  Contact me (610.933.5246 x122 or lkroos@all4inc.com) to discuss how ALL4 can support you.

New Source Review Reform: An Update (The Journey Continues)

Note:  this article assumes that the reader has a basic knowledge of the New Source Review permitting applicability process.  For those readers looking for more background, more details on the process can be found here.

In our most recent 4 The Record Article, Roy Rakiewicz provided background on the New Source Review (NSR) construction permitting program and examined how historic rulemaking activity by the U.S. EPA during the George W. Bush Administration could be an accurate indicator of upcoming NSR reform activity.  This look to the past was driven by the fact that William Wehrum, the current U.S. EPA Air and Radiation Program Administrator, was also involved during the Bush Administration working on similar regulatory program activities.  Since Roy’s update, we have had more of an opportunity to digest the most recent U.S. EPA NSR policy guidance and have a clearer picture of what is next.  This article is intended to update you on the latest activity and to provide insight into how to apply the most recent policy guidance activity to your projects.

The Policy Guidance Documents

While there have been Presidential memoranda covering the air permitting and National Ambient Air Quality Standard (NAAQS) review process, there are two NSR related guidance documents that are particularly impactful to day to day air quality permitting projects:

1. The Projected Actual Emissions enforceability memo released in December of 2017.
2. The Project Emissions Accounting memo released in March of 2018.

Projected Actual Emissions Enforceability

This memo generally covered how U.S. EPA will be involved (or not) in reviewing and enforcing the establishment of projected actual (post-project) emissions projections made for modification to existing major stationary NSR facilities.  Projected actual emissions (PAE) is a term defined by the NSR rules that is used (in accordance with the applicable rule) by major facilities to assess NSR applicability for modifications.  PAE, as used in NSR applicability determinations, are typically scrutinized by state regulatory agencies that are implementing state-specific NSR programs.  In the memo, U.S. EPA stated their intention to leave PAE calculations up to the applicant and to serve in an enforcement role only in the event that actual emissions, after a project is implemented, exceed the PAE presented in the construction permit application.  This distinction is important because it places the burden on facilities to make solid emissions projections, and leaves the decisions regarding these estimates up to the facility and permitting agency (not up to U.S. EPA enforcement).

Project Emissions Accounting

The basics of the Project Emissions Accounting memo can be found in Nick Leone’s blog introducing the guidance.  In summary, the guidance does two important things:

1. Allows for emissions decreases that are a part of a project being evaluated to be included in “Step 1” of the NSR applicability assessment.  Under the previous policy, only emissions increases could be included in Step 1.
2. States that the emissions decreases utilized in Step 1 do not need to be federally enforceable limitations because they are based on PAE (which, inherently, are not emissions limits).

These actions are in the context of the typical NSR applicability process that involves assessing emissions changes from the project being considered to see if “Step 2” (netting) is required.  Step 2 accounts for unrelated emissions increases and decreases during a contemporaneous lookback period that are summed with the project emissions changes.  Due to a combination of previous U.S. EPA guidance on netting and differing state agency netting practices, this step can add significant complications on its own to the NSR applicability process.

Accounting for emissions decreases during Step 1 of the applicability process is a common-sense measure that can streamline the evaluation for environmentally beneficial projects.  The simple example involves a boiler replacement.  I’ll borrow from Nick’s previous writeup:

“A common scenario impacted by [the project emissions accounting guidance] is the replacement of an emissions unit (e.g., installation of a new, higher capacity boiler).  Under the new policy, the emissions decreases from a 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 one 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 one, greatly increasing the likelihood that step two 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”.

The more complex application of the guidance applies to facility-wide projects that typically include a subset of physically modified equipment along with a host of “affected” equipment (not being physically modified but seeing a throughput/production increase as a result of the project).  Under the previous guidance, situations where PAE are lower than baseline actual emissions (i.e., emissions decreases) were “set to zero” and removed from strategic considerations of the NSR applicability process.  Under the new guidance, those projected emissions decreases could serve as a key aspect of an NSR avoidance strategy.  Emissions decreases from modified and affected emissions units can occur for a number of reasons:

1. A regulatory obligation resulted in an emissions reduction (in this instance baseline actual emissions (BAE) would need to be adjusted downward to reflect current emissions limits).
2. An operational change resulted in quantifiable emissions decreases.
3. A change to a control device for maintenance or operational purposes resulted in a quantifiable emissions decrease.

These emissions decreases, assuming they are associated with emissions units that are modified or affected for the current project being evaluated, could be utilized as part of the NSR applicability process without becoming federally enforceable emissions limits based on the new U.S. EPA guidance.

NSR Applicability Considerations at the State Level

There can be no authoritative advice given on state-specific project emissions accounting principles because the U.S. EPA guidance addresses the Federal NSR program.  The majority of state agencies implement their own NSR programs and can interpret their programs as they choose, even if their regulatory language closely mirrors the Federal regulatory language.  That means that decisions on emissions decreases and how they are handled will be at the discretion of the state agency.   We would recommend addressing the following areas with the state agency for your next project:

1. Confirm agreement on the basic principle that emissions decreases that are part of the project be included in Step 1 of the applicability process.
2. Summarize the Step 1 emissions decreases, the equipment that is involved, and the driver behind the emissions decreases.
3. Understand how the state agency will want to see the emissions decrease “tracked”; either as projected actual emissions that are tracked and/or reported after the project or as a Federally enforceable emissions limitation.  It is reasonable to assume that state agencies could want more assurance in the way of tracking, testing, or monitoring to document an emissions decrease than an emissions increase, even if the emissions increase is a projection rather than a Federally enforceable limit.

Even if the next big project isn’t defined, it will always be helpful to understand BAE and PAE for the primary emissions sources at your facility.  With this understanding, you can identify those emissions unit and pollutant line items that show an emissions decrease, identify why the emissions decrease is being calculated, and be better equipped to more quickly utilize those emissions decreases in the state agency conversations outlined above.

What’s Next?

Upcoming U.S. EPA guidance/rulemaking is anticipated on the following topics:

1. Guidance around the interpretation of ambient air as it relates to the placement of modeled receptors in areas to which the general public does not have reasonable (or legal) access.
2. Guidance and rulemaking around the aggregation of separate projects for assessing NSR applicability that will add clarity (and boundaries) to that process.

We will continue to keep you updated as U.S. EPA’s reform activity continues.  If you have questions (or good examples of the reforms in action!) feel free to contact me at cmccall@all4inc.com or 908.328.9429.

TCEQ Air Quality 101 Blog Series – PBR for Oil and Gas Handling and Production Facilities

As the summer months roll around the corner, many are focused on the hot summer activities: swimming, picnics, trips to the beach, and generally taking it easy.  If you’re in the Oil and Gas industry, there’s one more way you can take it easy: Permit by Rule (PBR) 30 Texas Administrative Code (TAC) 106.352: Oil and Gas Handling and Production Facilities!  With just a little bit of knowledge, and a few small steps, you can bypass the permitting stress, and cool off the rest of your summer!  For this installment of ALL4’s Texas Commission on Environmental Quality (TCEQ) Air Quality 101 Blog Series, we provide a brief overview of this PBR and how it applies to different facilities.

Background

First things first, you have to understand what a PBR is to use one.  PBRs are the permitting option between a facility with greater than de minimis emissions and a facility with emissions less than Standard Permit options.  Most PBRs are a quick and relatively painless way of saying that your facility meets a set of established standards, and doesn’t need to meet the additional compliance obligations that may come from a Standard Permit.  To determine if you even qualify for a PBR in the state of Texas, check 30 TAC 106.4 Requirements for Permitting by Rule and the applicability checklist known as the TCEQ-10149 to decide if this is an option for you.  If you think it is the right option, confirm that your facility can comply with the PBR conditions.  Once you do, you can complete a TCEQ-10228 Form, pay your registration fee, and begin constructing worry free!  But, that’s not all!  Once you’ve registered a PBR, there is no expiration date!  That means that once the PBR has entered the system, your facility does not need to renew its PBR unless you make significant modifications or add new equipment.

Non-Barnett Shale PBR

After determining if a PBR is right for you, you will then determine which section of 30 TAC 106.352 applies to you.  If your facility is located in the Barnett Shale region (Cooke, Dallas, Denton, Ellis, Erath, Hill, Hood, Jack, Johnson, Montague, Palo Pinto, Parker, Somervell, Tarrant, and Wise counties) and constructed after April 1, 2011, then 30 TAC 106.352 (a) – (k) applies to you, otherwise, oil and gas handling and producing facilities only have to meet the requirements for 30 TAC 106.352(l).  30 TAC 106.352(l) is straightforward and less stringent.  The regulation references additional requirements in 30 TAC 106.492 for Flares and 30 TAC 106.512 for Stationary Engines and Turbines.  The regulation then sets forth emissions limits and additional requirements for sour gas facilities [facilities with greater than 24 ppm hydrogen sulfide (H₂S) in their natural gas].  The requirements include a minimum stack height of 20 feet for units emitting H₂S, a distance of ¼ mile between any receptors and sulfur producing units, and a PI-7 registration for sour gas facilities.  Sour gas facility notifications under this section are subject to a 30-day review period prior to being accepted.  As long as these requirements are met, a production facility is able to obtain a PBR under 30 TAC 106.352(l).  As of February 1, 2018, all PBRs and standard permits must be submitted electronically through State of Texas Environmental Electronic Reporting System (STEERS) with a fee of $450 for 30 TAC 106.352(l) PBRs.

Barnett Shale PBR

Facilities in the Barnett Shale region however, need to meet the minimum requirements set forth in 30 TAC 106.352(e) Best Management Practices (BMP) and Minimum Requirements, such as a maintenance plan, leak detection and repair (LDAR) program, and control equipment requirements.  A facility must also meet the most stringent [30 TAC 106.352(g) Level 1 Requirements] emissions limits or less stringent [30 TAC 106.352(h) Level 2 Requirements] emissions limits depending on the outcome of their impact evaluation.  The impact evaluation required by 106.352(k) Emission Limits Based on Impacts Evaluation, determines the impact on nitrogen oxides (NO_x), sulfur dioxide (SO₂), and H₂S and the evaluation is based on both emissions level and distance of property line and receptor location criteria.  Level 1 requirements are implemented if there is a property line or receptor within ¼ mile and can meet the limits of 15 tons per year (tpy) volatile organic compounds (VOC), 100 tpy NO_X and SO₂, and 20.6 tpy H₂S.  Level 2 requirements are implemented for facilities that must meet the 25 tpy VOC, 250 tpy NO_X and SO₂, and 25 tpy H₂S limits, but the closest receptor is at least ½ mile away.

A facility in this region must also follow the requirements listed in 30 TAC 106.352(f) Notification, Certification, and Registration Requirements, such as submitting a Core Data Form, records of maintenance, startup, and shutdown (MSS) activities, and register maximum emissions estimates.  These permits must also be must be submitted electronically through STEERS with a fee of $175 for Level 1 registration and $400 for a Level 2 registration.  Once the facility has notified the TCEQ, they have up to a 30-day review period prior to being approved.  The rule further lists recordkeeping, sampling, and monitoring required for each site based on engine type, size, and manufacture date.

With such a streamlined process and shortened air permitting timeline, this oil and gas PBR is sure to help you get on to construction and begin operating sooner so you can free up your schedule for more summer fun.  If you think you might qualify for this PBR, or you have questions on this blog do not hesitate to contact us.  Stay tuned for our next installment of our TCEQ Air Quality 101 Blog Series (www.all4inc.com/texas).  Thanks for reading!

Georgia A&WMA Regulatory Update Conference: A Recap

The Georgia Chapter of the Air and Waste Management Association (A&WMA) held their annual regulatory update conference on May 16, 2018.  The event included various panels and presentations from industry representatives, consultants, Georgia Environmental Protection Division (GEPD), and the United States Environmental Protection Agency (U.S. EPA).  The key topics that were addressed during this year’s event are summarized below:

Major New Source Review (NSR) Guidance from U.S. EPA

The most popular topic of the day was the various major NSR permitting guidance memos that have been published by U.S. EPA about project emissions accounting, source and/or project aggregation, Actual-to-Projected-Actual emissions, etc.  GEPD’s message to facilities regarding the updated major NSR guidance was clear: talk to your state regulators early on in project planning/permitting to determine how the state is approaching the new guidance and how facilities can incorporate the guidance into permitting proposed projects.  While GEPD has indicated that they will be implementing most of the published U.S. EPA guidance, they are reacting to the new guidance just as much as facilities and consultants are reacting to it, that is, with a degree of uncertainty.  It is better to have additional conversations with GEPD early on in permitting projects so that facilities, consultants, and state regulators can work through the new guidance together and prevent headaches along the way.

Georgia-Specific Regulatory Updates

The Board of Natural Resources has voted to adopt three proposed revisions to the Rules for Air Quality Control codified at Chapter 391-3-1.

• The first revision, codified at 391-3-1-.03(8) for Permit Requirements, removed the “Additional Provisions for Ozone Non-Attainment Areas for Counties that were Formerly Part of the 1-hour Ozone Non-Attainment Area.”  These provisions were removed because the area has been re-designated to attainment status and the U.S. EPA has revoked the 1-hour ozone standard.

• The second revision, codified at 391-3-1-.03(10) for Title V Operating Permits (TVOP), relaxed the major source permitting thresholds from 25 tons per year (tpy) to 100 tpy of nitrogen oxides (NO_X) and volatile organic compounds (VOC) for 13 counties that were previously designated as severe nonattainment areas.

• The final revision, codified at 391-3-1-.03(9) for Permit Fees, revises the dollar-per-ton rate for calendar year 2017 emissions fees and also creates a permit application fee.  The permit application fee, discussed in a previous ALL4 blog, will be effective March 1, 2019.  GEPD has added the permit application fee because revenue from annual facility emissions fees have decreased as a result of decreasing emissions.  The income from the permit application fees will stay within GEPD’s TVOP program.  The Draft Air Permit Fee Manual has been updated with the revised dollar-per-ton rates for annual emissions and includes the new application fees for review.

If you have any questions on U.S. EPA published major NSR guidance, project permitting with respect to U.S. EPA NSR guidance, or Georgia-specific regulatory updates, please don’t hesitate to reach out to me at 678.460.0324 x213 or sarner@all4inc.com.  Thanks for reading!

Good Morning, U.S. EPA is on Their Way…

This article is available as a podcast episode on ALL4’s Air Quality Insider   

“Good Morning, U.S. EPA is notifying your Facility that we will be on-site for an inspection on Wednesday and Thursday next week.  Attached is a list of items U.S. EPA would like to review while on-site.”

This is NOT the best notification to receive before heading into the weekend, especially when the accompanying document includes almost 20 specific items (with several corresponding bullet points) that require detailed responses.

If you are an environmental coordinator, what goes through your mind when you are notified of a surprise U.S. EPA on-site compliance inspection?  Fear?  Nervousness?  Confidence?  Regardless, the clock starts ticking and the countdown until your inspection has begun… are you prepared?

In this situation, the Facility (our client) sent the list of U.S. EPA requests to us to consider and we asked what type of support they wanted.  ALL4 has been working closely with this client for several years, so we felt good about where they stood regarding their air compliance status and so did they.  The client said that they would start going through the list and would ask us for support when needed.  And guess what… they did.  We even provided “non-visible” on-site support so that we could quickly respond if anything came up.

Unfortunately, surprise U.S. EPA compliance inspections are a fact of life for large industrial facilities.  The good news is that ALL4 has provided support to our clients before, during, and after various Federal and State compliance inspections.

Here are a few tips when preparing for an inspection, surprise or otherwise:

• Compile documentation in advance

If the inspection agency provides a list of items to review, you have a great roadmap.  To confirm you are prepared and allow for an efficient inspection, (1) Set up electronic files in labeled folders that correspond to the list of information requested by U.S. EPA and (2) Print out hard copies of information that would be best reviewed on paper.

• Expect the unexpected

Be prepared to provide a detailed tour of the Facility to the inspectors.  This includes having sufficient personal protective equipment (PPE) on hand and designating a single conference room for documentation review.  The inspectors can request additional information on the fly or even ask for all of the files to be provided on a USB drive that they can take with them.

• Don’t BS!

If you don’t have a file handy or you are unsure about something, do not BS the inspectors.  Simply let them know that you are unsure and you can follow up with the appropriate file or answer after the inspection.

• Ask “what comes next?”

Before the inspection comes to an end, ask the inspectors “what comes next?”  For example, should the Facility expect a written inspection report within two weeks?  A conference call the next day?  Follow up items to be requested?

In the event that you “get the call” from a regulator to announce an inspection, ALL4 can assist your Facility before (document prep), during (assisting your Facility Environmental contact), and after your inspection (follow-up support).  We also perform compliance audits and assessments, which can be used to better prepare facilities in advance of these surprise inspections.

Do you have an upcoming inspection and could use support?  Have you looked at your records recently to ensure that you have everything required by your operating permit organized and easily accessible?  Have you considered pre-emptively reviewing your documentation, organizing, and structuring your files in case an inspection comes up?  Have you had a good or bad experience with an inspector?  Share your experience below or feel free to reach out to any of our consultants to talk about it!  You can reach me at 610.933.5246 x129 or aessner@all4inc.com if you want to chat about my experience or need a hand.