2016 Look Ahead – ALL4 Perspective

As we do each year, ALL4 looks ahead to the upcoming new year and evaluates the air quality regulatory topics that may matter most to the regulated community. For 2016, it certainly will be the year of Boiler MACT, as facilities gear up to prepare plans and conduct performance testing. We see a continuing trend of electronic reporting and public access to such data. Finally, Federal enforcement initiatives and recently implemented programs are driving new monitoring requirements for affected facilities that will require collaboration between industry, consultants, and equipment vendors. We welcome your feedback on these, and other topics, as you read our articles on what will be hot in 2016.

Please feel free to take a look at the entire Look Ahead, or jump to an article below:

• Next Generation Compliance – The Final Frontier?
  
• Looking Into 2016 for the Oil and Gas Industry
  
• Regulation of Greenhouse Gases
  
• The SO2 Data Requirements Rule in 2016
  
• Again with the Data
  
• Benzene Fenceline Monitoring – The Next Phase of Monitoring and Public Transparency on Compliance
  
• Lessons Learned from E-Reporting
  
• RCRA Air Emissions Standards – When Regulatory Worlds Collide
  
• The Eight (8) “Ws” of RACT 2 – Who, What, When, Why, Where, In What Way, and By What Means
  
• Yes, More Toxic Release Inventory Revisions
  
• The Window is Closing:  A Case for Plantwide Applicability Limits Now
  
• Facilities, Start Your Engines!
  
• Refinery Sector Rule – Where Do I Start?
  
• 4 Rules: Beyond Boiler MACT

Looking Into 2016 for the Oil and Gas Industry | JP Kleinle

Throughout 2015, ALL4 has provided the Oil and Gas Industry with numerous updates on the regulatory happenings affecting the sector.  In this article we will look into the crystal ball to see what 2016 may hold.

• 2016 will be a year of change for greenhouse gas (GHG) reporting.  The amendments to 40 CFR Part 98, Subpart W (Mandatory GHG Reporting for Petroleum and Natural Gas Systems) become effective January 1, 2016 and will come into play for the 2016 calendar year.  GHG reporters will have to begin monitoring, recordkeeping, and calculating emissions in accordance with the amendments beginning January 1, 2016.  The first reports to be submitted using the amended requirements will be those submitted March 31, 2017, covering the reporting year 2016.  See ALL4’s December 2, 2015 blog on this topic.
• U.S. EPA is expected to take action on the comments for New Source Performance Standard (NSPS) Subpart OOOOa that were received on or before the December 4, 2015 comment period deadline.  As you may recall, these comments covered many topics including (but not limited to) applicability thresholds, methods of compliance, and definitions contained in the proposed rules.
• Will we finally get clarity on what constitutes “adjacent?”  2016 may be the year when U.S. EPA decides on a specific definition for the word adjacent.  U.S. EPA proposed two (2) different definitions; one (1) that relies on proximity, and one (1) that relies on functional interrelatedness (see ALL4’s September 14, 2014 blog on this topic).  Depending on the direction U.S. EPA chooses, this decision could have significant impact on the industry.
• In response to a long-time push from environmentalists, U.S. EPA has agreed to begin a rulemaking which would add natural gas processing facilities to the list of industry sectors subject to Toxic Release Inventory (TRI) reporting (see ALL4’s November 16, 2015 blog on this topic).  ALL4 will be watching this rulemaking closely as we move into 2016.
• On August 18, 2015, U.S. EPA posted draft Control Techniques Guidelines (CTGs) for the oil and gas industry in order to reduce volatile organic compound (VOC) emissions from existing oil and gas sources in ozone nonattainment areas, including the Ozone Transport Region (OTR).  Within two (2) years of the final issuance of the CTGs, U.S. EPA will require revisions to the appropriate State Implementation Plans (SIPs) (i.e., the States that include ozone nonattainment areas, including the OTR) to incorporate the changes in Reasonably Available Control Technology (RACT) regulations for the oil and gas industry, which will most likely be based on the information presented in these CTGs.   We should start to see this process taking shape in 2016.

As you can see, 2016 will be another busy regulatory year for the Oil and Gas Industry.  As always, ALL4 will continue to monitor the regulatory changes that are important to your business.  In 2016 we will continue to stand ready to support you with your regulatory needs.  We wish everyone in the Oil and Gas sector a happy and healthy new year.  Please contact JP Kleinle at (610) 933-5246, extension 120, jkleinle@all4inc.com or Bob Kuklentz at (610) 933-5246, extension 124, rkuklentz@all4inc.com to discuss Oil and Gas Industry compliance concerns.

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Regulation of Greenhouse Gases | ALL4 Staff

Clean Power Plan

Around this time last year we could only speculate as to when U.S. EPA would finally finalize its highly discussed and oft-revised Clean Power Plan.  U.S. EPA came forward on August 3, 2015 with the final version of the Clean Power Plan, which consists of the following components:

1. Standards of Performance for New Stationary Sources (i.e., the NSPS) for New Electric Generating Units (EGUs)
2. Carbon Pollution Emission Guidelines for Existing EGUs
3. Carbon Pollution Standards for Modified and Reconstructed EGUs

How can an EGU expect to be impacted in 2016?  Construction of new (or modification or reconstruction of existing) steam generating units, integrated gasification combined cycle (IGCC) units, or stationary combustion turbines will need to be evaluated henceforth in terms of the new 40 CFR Part 60, Subpart TTTT if the unit has a base load rating of greater than 250 million British thermal units per hour (MMBtu/hr) of fossil fuel and serves a generator capable of selling greater than 25 megawatts (MW) of electricity to a utility power distribution system (grid).  In short, these units will need to be able to comply with the carbon dioxide (CO2) emissions standards in either Table 1 (steam generating and IGCC units) or Table 2 (combustion turbines) to Subpart TTTT following completion of the proposed project.  If you are responsible for an EGU and contemplating a future construction project, we encourage you to review the new performance standards with your ALL4 Project Manager to understand how you will be impacted.

What about an existing EGU that is not planning a project in the short-term?  An existing EGU by itself won’t be immediately affected by the Carbon Pollution Emission Guidelines for Existing EGUs because these are guidelines for states.  But an existing EGU would be wise to get clear on its State’s current position around achieving the rule’s CO2 reduction goals.  U.S. EPA has proposed state-specific rate-based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve a 30% CO2 emissions decrease nationwide by 2030.  States have until September 2016 (or September 2018 with an approved extension) to submit their plans for approval.  In the interim, states are busy reaching a decision as to whether they will develop and submit a plan or otherwise default to the federal plan.  Because the Clean Power Plan allows for significant flexibility, states also need to decide how they will achieve their goals — develop individual plans, join in a multiple-state plan, or opt into an interstate cap-and-trade program.  States developing individual plans can elect to meet a rate-based goal in pounds per megawatt hour (lb/MWh), a mass-based goal in tons of CO2, or mass-based goals with a new source compliment in tons of CO2.  If a state opts for an interstate cap-and-trade program, the states involved must have the same plan basis (mass- or rate- goal).

Need help figuring the out Clean Power Plan or assistance determining if your facility is subject to the GHG NSPS?  Please contact ALL4.

GHG Reporting Rule

Through the Mandatory GHG Reporting Rule, U.S. EPA collects and publishes emissions data from individual facilities that are subject to one (1) or more of the over 40 individual subparts of 40 CFR Part 98.  To date, Part 98 has been amended more than 25 times since its initial publication in October 2009 in order to add new source categories and to make both clarifying and technical amendments.  U.S. EPA was once again active during October 2015 when it finalized new reporting requirements for onshore petroleum and natural gas gathering and boosting activities, onshore natural gas transmission pipelines, completions and workovers of oil wells with hydraulic fracturing, well identification numbers, and confidentiality determinations for new Subpart W data elements.  If you are responsible for reporting under Subpart W, we encourage you to review these recent amendments with your ALL4 Project Manager to understand how you will be impacted during the current reporting season and beyond.

If you have questions regarding your facility’s status with regard to GHG reporting, permitting, or regulation, please contact Megan Uhler at (610) 933-5246 ext. 132 or muhler@all4inc.com.

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The SO2 Data Requirements Rule in 2016 | Dan Dix

If your facility has been affected by the sulfur dioxide (SO2) Data Requirements Rule (DRR), 2016 is going to be a busy and critical year.  In case you haven’t read one (1) of the many articles we’ve put out there on which facilities may be affected check out this page that summarizes them all.  Essentially you or your State Agency should have begun or will begin in 1st quarter 2016 determining the 1-hour SO2 National Ambient Air Quality Standards (NAAQS) designation status for areas without existing SO2 ambient monitoring systems.  To be affected your facility must emit more than 2,000 tons per year (TPY) of actual SO2 emissions, or is located in an area with a cluster of facilities that as a whole may have similar impacts to singles sources that emit greater than 2,000 TPY.  There are three (3) approaches laid out in the SO2 DRR for demonstrating attainment with the 1-hour SO2 NAAQS:

1. Conduct air dispersion modeling to show modeled attainment with the 1-hour SO2 NAAQS based on three (3) calendar years of actual emissions; or
2. Install an ambient monitor or monitors to measure ambient SO2 concentrations for a period of three (3) years. Often times dispersion modeling will still be used to identify areas of maximum modeled concentrations and therefore where an ambient monitor would be installed.
3. Take a federally enforceable permit limit to limit facility-wide SO2 emissions to less than 2,000 TPY of SO2.

The deadline to submit a dispersion modeling protocol or an ambient monitoring plan is July 1, 2016.  That means in 1st and 2nd quarter 2016 facilities need to conduct air quality modeling to determine if they can demonstrate compliance with the 1-hour SO2 NAAQS.  If an air quality modeling demonstration cannot demonstration compliance with the 1-hour SO2 NAAQS (which ALL4 is seeing more than U.S. EPA initially thought) then an ambient monitoring plan must be prepared.  The ambient monitoring plan will include air quality modeling used to properly site the location of an SO2 ambient monitoring station.  For sources that elect (and/or are forced) to go the ambient monitoring route this doesn’t leave too much time to meet the January 1, 2017 deadline for ambient monitors to be installed and operating.  For those lucky enough not to have experience with ambient monitoring programs six (6) months (or less because the State Agency and U.S. EPA will have to approve your ambient monitoring plan) is not a lot of time to procure, install, and test ambient monitoring equipment.  Therefore, ALL4 has been working with our clients to complete air quality modeling analysis a soon as possible and prepare dispersion modeling protocols or ambient monitoring plans for submittal to State Agencies and U.S. EPA well before the July 1, 2016 in an effort to get approval to move forward with the next steps.

The two (2) other deadlines that will require effort in 2016 is the submittal of an air quality modeling demonstration by January 13, 2017 for those that can demonstrate compliance with the SO2 NAAQS through air dispersion modeling.  Lastly, a 2,000 TPY SO2 federally enforceable limits will need to be established by January 13, 2017.  Happy 2016!

Please contact Dan Dix at (610) 933-5246, extension 118 or at ddix@all4inc.com to discuss SO2 DRR requirements.

Again with the Data | Eric Swisher

It seems every year I say the same thing, and in 2016 it is not any different.  Data collected by continuous monitoring systems (CMS) that are used for compliance purposes are going to be scrutinized by corporate auditors, regulatory agencies, and interested third parties.  Why?  Because it is a lot more readily available since every year more and more regulations are requiring electronic submittal of data.  In 2015 it was sources affect by the Portland Cement MACT.  In 2016 it will be sources subject the Major Source Boiler MACT and Refinery MACTs.  When will it end?  Never.  The data collected by CMS are by far the most transparent look at your facility’s operations and compliance demonstration.  Once it is submitted in an electronic format it is available to be scrutinized by anyone with minimal Excel skills.  What will they find?  What questions will that have?  Can you answer them?

Do not think that if your facility is using a Data Acquisition and Handling System (DAHS) that your little “magic black box” where all of your data go “magically” spits out compliance demonstrations.  It is time to understand process for collecting the data points, validations, averaging periods, alarm sequences, and reporting tools.  Even worse if your compliance is demonstrated simply using legacy spreadsheets create by someone else to validate and generate compliance averages.  I suppose if we bury our heads in the sand in 2016 that all this will go away, or I will be writing about data management in next year’s annual look-ahead article.

Contact Eric Swisher at (610) 933-5246, extension 117, or at eswisher@all4inc.com with your data monitoring and management questions.

Benzene Fenceline Monitoring – The Next Phase of Monitoring and Public Transparency on Compliance | Nick Leone

The Petroleum Refinery Rule Package was published in the Federal Register on December 1, 2015 officially starting the two (2) year process of preparing for and implementing the 40 CFR Part 63, Subpart CC benzene fenceline monitoring (BFM) requirements.  One (1) specific BFM requirement included as part of Subpart CC is the collection of bi-weekly air samples around the “fenceline” of refineries for benzene analysis.  U.S. EPA’s intent behind the BFM requirement is to implement a program to identify fugitive emissions from refineries and to be able to implement corrective action to minimize those emissions more quickly than would otherwise be implemented.  The default monitoring method in the rule is a passive technique, in conjunction with  onsite or locally sourced (meeting data quality and representativeness criteria) hourly meteorological data, to quantify benzene concentrations at the fenceline.  Refineries are required to begin their BFM sampling program so that the first official sampling episode begins on or before February 1, 2018.  Given this relatively new monitoring approach imposed on refineries by U.S. EPA, here are a few considerations:

• Advanced Monitoring – sophisticated monitoring technology exists to enable facilities (and regulators) to “see” equipment leaks and fugitive emissions that were previously invisible.  Facilities will now be generating a tremendous amount of data and because the measurement technique is time integrated (i.e., over a 2-week period) and is measuring ambient/fugitive emissions (as opposed to stack/point source emissions), outside influences can impact the results.  For example, tailpipe emissions from nearby roadways or other industrial facilities with upwind emissions.

• Information Age – With advances in technology, information is abundant and quickly accessible.  While this has benefits making all parties more informed, is more information really better?  High quality data of a lesser quantity may provide much more insight than a large amount of poor quality data.  U.S. EPA is looking to provide the public with more information requiring that refineries report BFM data and which will be available to the public.  Have you thought about how this data will be managed and quality assured?  Will the data be presented in a way that can be clearly understood by the public?

• Plan for Success – The default method proposed by U.S. EPA is a passive analytical technique that is not complicated when compared to the sophistication of operation and maintenance associated with other analytical techniques such as  a continuous emissions monitoring system (CEMS).  With passive analytical techniques, it is the outside influences and the interpretation of the resulting data that present the challenge.  What happens when an abnormally high benzene concentration result is reported from the lab?  Were emissions even from your facility?  How do facilities handle missing data points due to lost/damaged samples or vandalism?  A site-specific monitoring plan (SSMP) should not be another regulatory checkbox as this is where the planning should occur (prior to sampler deployment).  The SSMP can be and should be an asset as the foundation and the key to a successful monitoring program.

Refineries are being tasked with implementing a monitoring program based on a philosophy new to them.  This comes with new challenges for the industry.  There is much experience to be shared from monitoring programs implemented elsewhere.  Please contact Nicholas Leone at (610) 933-5246, extension 121 or at nleone@all4inc.com to discuss your benzene fenceline monitoring concerns.

Lessons Learned from E-Reporting | Kayla Turney

Various subparts to 40 CFR Parts 60 and 63 [Standards of Performance for New Stationary Sources, commonly referred to as New Source Performance Standards (NSPS), and National Emission Standards of Hazardous Air Pollutants (NESHAPs), respectively] have electronic reporting (“E-Reporting”) requirements that use U.S. EPA’s new Compliance and Emissions Data Reporting Interface (CEDRI), with some reports needing to be generated using the Electronic Reporting Tool (ERT) before being uploaded to CEDRI. As with any new program, you can expect there are a number of nuances that still need to be worked out of the system. This past year has been one of learning, adapting, and a little frustration with E-Reporting. Here are the top five (5) lessons I’ve learned.

1. Data entry includes more than just “the basics”

   When entering performance test or relative accuracy test audit (RATA) reports into ERT, you need to enter more than just the results. This can become a very large task. Not only do the results need to be entered, but a complete test plan needs to be entered as well. Additional example items required to be entered into ERT include:
   – Sampling location information (e.g., upstream/downstream distance from disturbances)
   – Control device parameters monitored (e.g., wet scrubber liquid flowrate)
   – Calibration gas concentrations
   – Fuel sampling lab data
   – Pitot coefficients

2. Some data fields must be customized for the report to compile

   The E-Reporting tools (e.g., ERT) do not vary between subparts. For this reason, sometimes a “required” data field might not be applicable to a particular report you are preparing. In order for the report to compile, sometimes data fields must be customized (typically as zero). For example: maybe you did not sample moisture during your stack test but ERT requires moisture values be entered. There is no way to actually tell which data fields are required other than trial and error. Leading into my next lesson…

3. Comment, comment, comment

   The best thing you can do is to comment and explain your work. Since the systems are not perfect and may not exactly fit your facility needs, it is important to insert comments, attachments, etc. whenever possible to justify why you did what you did (e.g., entered dummy zeros).

4. ERT reports can fail to compile even if nothing is wrong with the data

   Yes, you read that correctly. ERT reports can fail to compile into the file suitable for upload to CEDRI due to software bugs. Sometimes the report itself can be perfect but the software just won’t allow it to generate. Unfortunately, there is no way to know whether the issue lies with your data or with the software. All you can do is shutdown the program, shutdown your computer, sometimes re-install the software, cross your fingers, and hope for the best on the next try.

5. E-Reporting isn’t going to go away

   There are more and more NSPS and NESHAPs with promulgated E-Reporting requirements and the number is only going to grow. We are living in a computer age and U.S. EPA is no exception. It is better to get ahead of the curve when it comes to E-Reporting.

Please contact Kayla Turney at (610) 933-5246, extension 143 or at kturney@all4inc.com to discuss your E-Reporting compliance concerns.

RCRA Air Emissions Standards – When Regulatory Worlds Collide | ALL4 Staff

Every three (3) years, the U.S. Environmental Protection Agency (U.S. EPA) selects National Enforcement Initiatives (NEIs) to address specific environmental problems, risks, or patterns of noncompliance. According to U.S. EPA, these initiatives are reevaluated every three (3) years in order to focus Federal enforcement resources on the most important environmental problems where noncompliance is a significant contributing factor, and where Federal enforcement attention can have a significant impact. On September 15, 2015, U.S. EPA released for public comment a planning document containing its recommendations for NEIs for fiscal year (FY) 2017 through FY 2019.  In this publication, U.S. EPA reviewed the status of the existing NEIs (i.e., FY 2014-2016) and presented NEIs for consideration for FY 2017-2019.  Not surprisingly in this time of residual risk and technology reviews for National Emissions Standards for Hazardous Air Pollutants (NESHAPs) and associated Maximum Achievable Control Technology (MACT) requirements, air toxics emissions remain a focus for U.S. EPA. However, what is different for FY 2017-2019 is the inclusion of air toxics emissions from the handling of hazardous waste, which are regulated under the Resource Conservation and Recovery Act (RCRA) and its associated regulations in 40 CFR Parts 260-265. Huh? Air emissions are also regulated under hazardous waste regulations? Yes!

For large quantity generators (LQGs) of hazardous waste, as well as treatment, storage, and disposal facilities (TSDFs) such as cement kilns burning hazardous wastes and solvent recovery (distillation, extraction, etc.) and fuel blending facilities, Subparts AA, BB, and CC to 40 CFR Parts 264 and 2651 contain air emissions standards for process vents; equipment leaks; and, tanks, surface impoundments, and containers. According to U.S. EPA, its observations during field work, as well as the publicly available compliance information on Enforcement and Compliance History Online (ECHO), widespread violations of the air emission requirements under RCRA are a significant contributor of air toxics emissions.  U.S. EPA’s concern that facilities are not properly managing (which can include emissions controls, monitoring, recordkeeping and reporting) hazardous waste air emissions is the reason for the inclusion in the proposed NEIs for FY 2017-2019.

The assorted maze of the applicability criteria in Subparts AA, BB, and CC can be tricky, but ALL4 is here to help. So what should you do now? First, if you know you are an LQG of hazardous waste or a TSDF (if you do not know, we can help with that too) and you have evaluated the applicability of these subparts, pat yourself on the back, but then review your current facility operations. Has anything changed since you last conducted an applicability evaluation: a new tank; a change in service of valves and flanges? Have you documented your evaluation, particularly if these subparts do not apply? If they do apply, are you complying with the emissions control, monitoring, and related recordkeeping and reporting requirements? Essentially, your first course of action if these subparts apply is to conduct an audit of your operations and address the gaps now before you hear a knock on your door. If you never have looked at these subparts, now is the time to review the applicability criteria and make plans to address the gaps that are identified posthaste.

The proposed NEI for RCRA air emissions is ideally suited for U.S. EPA’s Next Generation enforcement model (there was a reason I wrote about it in our 2015 Look Ahead series!). The fugitive emissions from tanks and equipment leaks are tailor made for the advanced monitoring techniques of the Next Generation model (“making the invisible visible” to coin a phrase I just heard on a recent webinar). These advanced monitoring techniques are not just coming; they are here and already being used. That fact, and this potential NEI should move “identify RCRA air emissions standards applicability” near the top of your to do list in 2016.

Again, these subparts only apply to LQGs of hazardous waste and TSDFs, so if you are neither of these, you are in the clear for now. For those that are subject, don’t forget that FY 2017 begins October 1, 2016, so you do not have as much time as you might think to get started.

The Eight (8) “Ws” of RACT 2 – Who, What, When, Why, Where, In What Way, and By What Means | Ron Harding

The revised Final-Form Reasonably Available Control Technology (RACT) 2 Rule was approved by the Pennsylvania Environmental Quality Board (EQB) on November 17, 2015.  It’s now in the last administrative stages on its way to being finalized and published in the Pennsylvania Bulletin.  As an air quality rule that applies to major sources located within the Commonwealth of Pennsylvania, RACT 2 could potentially have a significant impact on a facility’s nitrogen oxides (NOX) and volatile organic compound (VOC) emitting operations; not to mention their operating budgets, and the already full plates of their environmental compliance staff.  Below we address the eight (8) “Ws” of RACT 2 as a primer for our readers.

WHO – The players…

• Pennsylvania Department of Environmental Protection (PADEP):
  • Information presented by PADEP during the November 17, 2015 EQB meeting pertaining to the revised Final-Form RACT 2 Rule can be found here.  The presentation provides a nice background summary of the RACT 2 Rule.

• Major Sources within the Commonwealth:
  • The revised Final-Form RACT 2 Rule applies statewide to facilities with potential emissions that exceed 100 tons per year (tpy) for NOX and 50 tpy for VOC.

WHAT – The revised rules…read them, know them, love them…

• Revised Final-Form RACT 2 Rules (25 PA Code §129.96-100)
• Want information?  ALL4 has developed several blogposts delving into the “what” of the RACT 2 Rule in more detail which can be found in the RACT 2 Toolbox, here.  Any and all RACT 2 related content developed by ALL4 will find its way to the RACT 2 Toolbox page.  Check back regularly.

WHEN – Part of the when is something of an open question, another part is definitely not…

• During the December 10, 2015 Air Quality Technical Advisory Committee (AQTAC) meeting PADEP’s Director, Bureau of Air. Quality, Joyce Epps, communicated that the RACT 2 Rule would move to the Independent Regulatory Review Commission (IRRC) for review in late January 2016 or early February 2016.
• Ms. Epps also communicated that the RACT 2 Rule won’t be published in the Pennsylvania Bulletin until March 2016 or possibly as late as April 2016.
• RACT 2 proposals, operating permit modification applications, and related Plan Approval Applications (PAAs) are due to the PADEP within six (6) months of final issuance of the RACT 2 Rule in the Pennsylvania Bulletin; best case = September 2016, worst case = October 2016.
• The compliance date for the RACT 2 Rule is January 1, 2017.  This compliance date is mandated by U.S. EPA, is firm, and will not change, meaning that all information necessary to demonstrate compliance with applicable RACT 2 Rule requirements needs to be generated between now and January 1, 2017 and submitted to PADEP by January 1, 2017.
• An extension of the compliance date is only possible for facilities that submit a PAA to install a control device, make a physical change, or change in the method of operation to comply with applicable RACT 2 requirements.  In such cases, the compliance date is extended to three (3) years from the date of issuance of a resulting Plan Approval, meaning the maximum time period this process could be extended is 4.5 years [18 month maximum for PADEP to review a PAA plus a three (3) year extension from the date of final Plan Approval issuance = 4.5 years, give or take].

WHY – Is the why everything?  I guess, it is the why after all…also because…

• You operate a facility that has the potential to emit NOX and VOC at levels above the applicability threshold within the Commonwealth of Pennsylvania and you have a regulatory obligation to analyze, address, and comply with RACT 2 requirements; and because at this point you only have a year to do so.

WHERE – This one seems relatively obvious…

• “Birthplace of a mighty nation, Keystone of the land.”  Yup, Pennsylvania and Pennsylvania only.

In What Way – This is what you’ll need to evaluate and potentially develop…not to worry, we can help…

• RACT 2 Applicability Analyses.
• RACT 2 Compliance Proposals:
  • Including compliance strategies:
    • Compliance with presumptive RACT 2 Rule requirements.
    • Compliance via NOX Averaging Plans and development of such plans.
    • Compliance via alternative case-by-case RACT 2 proposal including 5-step, top-down, “BACT-like” RACT 2 control technology feasibility and cost analyses.
    • Operating Permit Modification Applications to incorporate the applicable RACT 2 requirements into a facility’s operating permit or to roll in the RACT 2 requirements resulting from Plan Approval issuance.
    • PAAs proposing to install a control device, make a physical change, or change in the method of operation to comply with applicable RACT 2 requirements.

By What Means – Need to learn more about how to comply?  Join us on March 1, 2016 and get trained…

With a compliance date of January 1, 2017, affected facilities operating within the Commonwealth will need to evaluate the applicability and impact of RACT 2 on their operations, assess the need to develop a RACT 2 proposal, and submit said proposal to the PADEP within six (6) months from issuance of the final rule in the Pennsylvania Bulletin (potentially anytime between January 1, 2016 and April 30, 2016).

To assist facilities with this process, ALL4 and PADEP will be jointly presenting a training and Q&A session on the revised Final-Form RACT 2 Rule, RACT 2 Review, on Tuesday, March 1, 2016.  The RACT 2 Review will take place at the Harrisburg University of Science and Technology’s Academic Center and will provide details about how to comply with the revised Final-Form RACT 2 Rule, as well as answer questions specific to your facility.  Please register for the event in advance here or below.

Want to find out more about RACT 2, give me a call, Ron Harding, Project Manager for ALL4 at 610-933-5246 ext. 119, or call John Slade, Senior Consultant, at 717-822-0009.

Yes, More Toxic Release Inventory Revisions | ALL4 Staff

Toxic Release Inventory (TRI) submittals are due to both U.S. EPA and a facility’s respective state agency by July 1 of each year pursuant to Section 313 of the Emergency Planning and Community Right-to-Know Act (EPCRA).  On November 23, 2016, U.S. EPA added 1-bromopropane to the list of toxic chemicals subject to reporting under this program.  1-bromopropane may be used at your facility as a liquid or gaseous solvent.  As indicated in U.S. EPA’s November 23, 2016 Federal Register Notice, you may be potentially affected by this action if your manufacture, process, or otherwise use 1-bromopropane.  If you are responsible for reporting to the TRI program, we encourage you to review this new reporting requirement and understand the likelihood of your manufacturing, processing, or otherwise use of 1-bromopropane. The first TRI report for releases of 1-bromopropane is due July 1, 2017, covering calendar year 2016.  So the new year means beginning to actively monitor 1-bromopropane to document if you exceed a manufacturing, processing, or otherwise use threshold in preparation of your July 1, 2017 TRI report.

If you have questions regarding your facility’s status with regard to TRI reporting, please contact ALL4.

The Window is Closing:  A Case for Plantwide Applicability Limits Now | John Egan

PAL is the acronym for Plantwide Applicability Limit.  A PAL based on past actual emissions establishes a single, facility-wide emission limit for designated regulated new source review (NSR) pollutants. The PAL provisions that exist in the Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) regulations are part of the NSR Reform package that also brought us the “actual-to-projected-actual” test and the “excludable emissions” concepts, which were finalized in December 2002.  Provisions for PALs are cooudified in the Federal regulations at 40 CFR §52.21(aa), §51.165(f), and Appendix S to Part 51 – Emission Offset Interpretative Ruling.  Most SIP approved state NSR programs also include PAL provisions.  PAL based permits represent a legitimate means for facilities to avoid the difficulties that are now a routine part of major NSR permitting.  Several key PAL benefits include:

• As long as the facility demonstrates compliance with the PAL, physical changes and changes in the method of operation are not major modifications and projects do not require approval under applicable PSD (or NNSR) programs.
• A PAL will let you preserve your baseline actual emission rate for at least 10 years and possible longer.
• Historical NSR avoidance limits (e.g., emissions, production, and hours of operation) are eliminated by a PAL.
• The facility manages emissions, operations, and projects to allow growth while maintaining emissions below the PAL levels.
• Regulatory agency review times for modifications are compressed and even eliminated in many instances.

PALs can be established for one (1) or more regulated NSR pollutant at an existing major stationary source.  Each PAL level is based on a 12-month rolling total, expressed in tons of pollutant per year.  Compliance with PALs must be demonstrated monthly during the term of the PAL permit.  Each limit is generally established based on the average annual (e.g., baseline) emission rate for a 24-month consecutive period during the prior 10 years of facility operation. In most states, different baselines can be established for different regulated NSR pollutants. The PSD (or NNSR) significant increase threshold for the regulated NSR pollutant that is specified in the rule is then added to the baseline actual emission rate to set the PAL level [eg., 40 tons for sulfur dioxide (SO2)].  As mentioned above, a primary advantage of a PAL permit is that as long as the facility demonstrates compliance with the PAL, physical changes and changes in the method of operation are not major modifications and projects do not require approval under applicable PSD (or NNSR) programs.  Facilities with PALs may still be required to obtain state minor construction permits to initiate facility changes, but the typical NSR applicability analyses associated with every project at an existing major stationary source and the complications associated with PSD/NNSR for major modifications go away.

Because the PAL level represents an NSR “bright-line,” facilities with PALs can evaluate projects and determine how they will comply with the PALs, rather than being required to consider PSD (or NNSR), best available control technology (BACT) or lowest achievable emission rate (LAER) technology, purchase emission offsets, and demonstrate NAAQS compliance.  Under a PAL permit, decisions regarding process and air pollution control technology remain with the source, and the facility baseline emissions are preserved for at least ten (10) years.  Most importantly, if a PAL permit makes sense for a facility, the facility can potentially have an economic advantage over competitors that make similar modifications and must go through the time consuming and costly major NSR permitting process.

As mentioned, one key benefit of a PAL based permit is to preserve one or more beneficial baseline periods that may have occurred at your facility prior to the “great recession”.  Why is this important now?  Because the PAL rules, like the PSD rules for non-electric generating units (EGUs), allow facilities to “look back” ten (10) years to establish 24-month periods for regulated NSR pollutants.  As we enter into 2016, the ten (10) year window that includes pre-recession baseline actual emissions is rapidly closing.  Based on simple math, a higher BAE will result in a higher PAL level.  In order to lock in beneficial historical (2006) baseline periods before they disappear, facilities contemplating PALs should be in action now.  Please contact John Egan at (610) 933-5246, extension 114 or at jegan@all4inc.com with any PAL related questions that you may have.

Facilities, Start Your Engines! | Sally Atkins and Sharon Sadler

In 2015, ALL4 opened the Washington, D.C. office, further expanding its services in the mid-Atlantic region with an added focus on healthcare, property management, data centers, and higher education.  The primary air quality-regulated sources for such facilities include engines, boilers, and refrigerant-containing equipment.  [These sources can trigger environmental regulations in addition to air quality so let’s not forget about those!  For more information, attend Sally Atkins’ presentation at the (free) National Facilities Management & Technology Conference/Exposition in Baltimore on March 24, 2016.]

Looking ahead to 2016, we foresee the most relevant regulatory activity involving engines…

Prior to May 2015, there hasn’t been much chatter around Federal stationary internal combustion engine regulations…and then Delaware took the U.S. EPA to court over the use of emergency generators during emergency demand response events!  The U.S. EPA proposes to issue revised regulations in accordance with the D.C. Circuit’s ruling and the U.S. EPA’s voluntary remand within the next year but those engines participating in emergency demand response programs may be impacted in 2016.  In the meantime, U.S. EPA has issued proposed changes to 40 CFR Part 60, Subpart IIII to allow the deactivation of emissions controls (such as what you’d find with Tier 4-certified diesel engines) when generators are called into service for a qualifying emergency situation; these engines would only have to meet Tier 1 standards during such times.  Where continued generator operation is required to serve a mission-critical or life safety purpose, this relief will be very impactful.  Let’s also not forget about the March 31, 2016 reporting requirement for engines operated for certain purposes specified in the three (3) Federal engine regulations…if you haven’t experienced U.S. EPA’s web-based portal CEDRI, now may be your chance!

Several alternative options will continue to be available as you evaluate your emergency back-up power needs.  For those looking to minimize on-site fuel storage, or who have trouble receiving diesel fuel when needed, bi-fuel (i.e., the concurrent firing of natural gas and diesel) may be an option.  In a July 2013 decision, EPA officially established their position that the conversion of a diesel engine to bi-fuel was not considered tampering under the Clean Air Act (differing from previous informal correspondence).  However, the installation of control technology and performance testing may be required, particularly if the diesel engine was a certified unit.  Where you also use large boilers, a combined heat-power (CHP) option can be considered to increase energy efficiency.  Economic incentives are available through many states and natural gas proponents but there are also downsides to consider.  These alternatives, among others, require advance consideration of the impact to your air permit or where Federal and state engine regulations may apply, so involve your environmental support early.

In 2016, let’s explore how the nuances of Federal and state engine regulations affect your facilities and where alternative technologies can maximize your resources.

Please contact Sally Atkins (satkins@all4inc.com, 571-392-2594) or Sharon Sadler (ssadler@all4inc.com, 571-392-2595) to discuss your environmental compliance needs.

Refinery Sector Rule – Where Do I Start? | Meghan Barber

By now, chances are you have heard about the recently finalized revisions to what is referred to as the Refinery Sector Rule.  The Refinery Sector Rule encompasses final revisions to refinery specific New Source Performance Standards (NSPS) and Maximum Achievable Control Technology (MACT) regulations [i.e., 40 CFR Part 60 Subparts J and Ja, and 40 CFR Part 63 Subparts CC and UUU (Refinery MACT 1 and Refinery MACT 2), respectively].  After all of the initial panic has died down, you may find yourself thinking, where do I start?

First and foremost, the official effective date of the finalized Refinery Sector Rule is February 1, 2016.  Any applicable new sources installed after February 1, 2016 must meet the requirements (as appropriate) of the Refinery Sector Rule upon startup.  A source is considered new if it was constructed on or after June 30, 2014.  Existing equipment has a variety of different deadlines by which compliance must be demonstrated, ranging from the effective date of the final rule (i.e., February 1, 2016) to three (3) years after the effective date (i.e., February 1, 2019).  Here’s a breakdown of the regulations for existing equipment which could have an impact on your facility in 2016.

1. Alternative Provisions for Periods of Startup and Shutdown:

   On February 1, 2016 your facility must comply with the revisions to the SSM provisions of the Refinery MACT 1 and 2.  Specifically, new work practice standards for process venting, a minimum oxygen operating limit for fluid catalytic cracking units (FCCU), minimum cyclone face velocity limits, and alternative monitoring for incinerator temperature and excess oxygen limits for sulfur recovery units (SRU), have been finalized for startup and shutdown events.

2. Marine Vessel Loading:

   On the effective date of the regulation, if your facility has a potential to emit less than 10 tons per year (year) of a single hazardous air pollutant (HAP) or 25 tpy of all combined HAPs or is located offshore, marine vessel loading operations will be required to use submerged filling based on the cargo filling line requirements found in 46 CFR §153.282.

3. Storage Vessels:

   Within 90 days of the effective date of the final rule (i.e., May 1, 2016), your facility will need to determine if existing storage vessels meet the new definition of a Group 1 storage vessel.  The definition of a Group 1 storage vessel was revised to include smaller tanks with lower vapor pressures.  An existing tank is classified as Group 1 if the tank has a capacity greater than or equal to 20,000 gallons but less than 40,000 gallons, with a maximum true vapor pressure greater than or equal to 1.9 pounds per square inch absolute (psia) and an annual average weight HAP content greater than 4%; or if the tank has a capacity greater than 40,000 gallons, with a maximum true vapor pressure greater than 0.75 psia and an annual average weight HAP content greater than 4%. It is critical for facilities to begin to determine which, if any existing tanks are newly defined as Group 1 storage vessels, as additional requirements will apply.

These new requirements have the potential to affect your facility’s current monitoring, recordkeeping and reporting requirements in 2016.  Now is the time to take action and begin to dig into how the rules apply to your facility and what may need to be done to demonstrate compliance. In addition to what was mentioned above, there are finalized requirements which do not have compliance deadlines in 2016, but may require time intensive planning and implementation such that compliance may be demonstrated by the future deadlines. These requirements may include, but are not limited to, compliance testing, method of operation for flares and delayed coking units, flare work practice standards, atmospheric pressure relief device (PRD) work practice requirements, and benzene fenceline monitoring.

Please contact Meghan Barber at (610) 933-5246, extension 130 or at mbarber@all4inc.com to discuss the next steps for demonstration compliance with the finalized Refinery Sector Rule.

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4 Rules: Beyond Boiler MACT | Lindsey Kroos

January 31, 2016 is practically here – one (1) week before Super Bowl Sunday, in fact.  With reconsiderations to the rule just recently finalized, are you ahead of the Major Source Boiler MACT compliance curve, or behind?  Or perhaps you have a 1-year extension of the compliance date to January 31, 2017.  We’ve seen it all, and expect to see a lot more activity next year, as sources without extensions have until July 29, 2016 to conduct performance tests, followed by establishing operating parameter limits, submitting data using U.S. EPA’s Electronic Reporting Tool (ERT), and submitting the Notification of Compliance Status (NOCS), among other things.  Energy assessments and initial tune-ups must be completed by the applicable compliance date.  Those with extensions need to remember that extensions apply on a unit by unit basis, which further complicates the compliance deadlines.

We have found that there is more than meets the eye around the pre-performance testing requirements.  Performance test plans, site-specific monitoring plans (SSMPs), and fuel analysis plans must be in place at least 60 days before the scheduled performance test.  The SSMPs in particular play an important role in establishing your facility’s compliance strategy due to complexities in the rule and site-specific nuances that must be addressed.  For example, certain continuous monitoring systems (CMS) have specific performance evaluation requirements that must be completed on an established frequency, including at or around the time of the initial performance test.

While Major Source Boiler MACT is certainly a hot topic, three (3) other related rules will see activity in 2016 as well.  The initial compliance date for Area Source Boiler MACT was in March 2014, which means that it’s about time for the next round of biennial tune-ups if not completed already.

Reconsiderations to the Commercial and Industrial Solid Waste Incineration (CISWI) rules were finalized on February 1, 2013.  Additional reconsiderations proposed in 2014 have not yet been finalized.  Existing sources are expected to have until February 7, 2018 to comply with the rule, but the actual compliance date will be established in individual State Plans, and could be earlier.  State Plans that establish a compliance date more than one (1) year after U.S. EPA approval of the State Plan must include enforceable increments of progress.  Affected sources located in states without U.S. EPA approved State Plans will be subject to the Federal Plan, which has not yet been promulgated.

Last but not least, the Non-Hazardous Secondary Materials (NHSM) rule, which determines whether NHSM are wastes when used as fuels or ingredients in combustion units, is expected to see some changes in 2016 as well.  Amendments were proposed in 2014 to add three materials to the list of categorical “non-waste” exemptions, including construction and demolition (C&D) wood, old corrugated cardboard (OCC) rejects, and creosote treated railroad ties.  The amendments are expected to be finalized in early 2016.

Feel free to contact me at 610.933.5246 x122 or lkroos@all4inc.com to discuss your facility’s compliance obligations for any of these 4 Rules.

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ERT and CEDRI: What the Heck Is It and How Does It Impact You?

You may have heard the terms Electronic Reporting Tool (ERT), Compliance and Emissions Data Reporting Interface (CEDRI), or Central Data Exchange (CDX) flying around lately and possibly thought to yourself, “Great, more acronyms. Exactly what the environmental compliance world needs.” But what do these terms really mean and should you be concerned?

DEFINE: To follow suit with the computer-age that is among us, U.S. EPA is transitioning certain forms of reporting to an electronic platform, also known as “E-Reporting”.  All E-Reporting shares a common home-base, which is CDX.  Reports are submitted to CDX using CEDRI.  Furthermore, some reports must be prepared using ERT before they can be uploaded to CEDRI.  Still with me?

EXAMPLES: Reports that currently have E-Reporting requirements include:

• Performance test results
• Continuous emissions monitoring systems (CEMS) relative accuracy test audit (RATA) results
• Notifications [e.g., Notification of Compliance Status (NOCS)]
• Compliance reports

I know what you are wondering next – does this impact me and my facility? That may be a hard question to answer with the guidance that is currently published.  As such, I’ve developed a flow chart to assist you.

If you fall to the left of this chart, here are your next steps:

Call me.  Why?  Because we can help you with any and all of your electronic reporting needs. We have a dedicated team, which I lead, who are experts in the world of E-Reporting and all of the oddities that come with it.

Merry Reporting!

Kayla

email: kturney@all4inc.com
phone: (610) 933-5246 x143

P.S. We are also developing an E-Reporting training program and would love your feedback.  What topics would you like to see in a training program? What issues have you encountered with E-Reporting?

Oxygen – We need it to live, and so does your 40 CFR Part 63, Subpart DDDDD Boiler!

Let’s talk about oxygen! Sure, we all know that it’s critical to life, but did you know that it is also a critical part of the major source Boiler MACT¹ rule? According to 40 CFR §63.7525(a), a boiler or process heater that is subject to a carbon monoxide (CO) emissions limit must install, operate, and maintain an oxygen (O₂) analyzer system, or install, certify, operate, and maintain a continuous emission monitoring system (CEMS) for CO and O₂.  Have you determined how you will demonstrate continuous compliance with the requirement to monitor O₂?  There are multiple ways to meet this requirement.  The following may be utilized:

• Boiler O₂ (for boilers without an O₂ trim system)
• O₂ trim system
• O₂ measured at the stack through an existing analyzer

Let’s take a closer look at the options.

For boilers without an O₂ trim system, an O₂ monitor must be used to measure and record the O₂ content in the boiler or process heater flue gas, boiler or process heater, firebox, or other appropriate location..  The data from this monitor would be reduced to 30-day rolling averages.  The 30-day rolling average would have to be maintained at or above the lowest hourly average measured during the most recent CO performance test.

One of the least burdensome methods is utilizing an O₂ trim system.  Pursuant to 40 CFR §63.7525(a)(7), a facility would operate an O₂ trim system at the O₂ level set no lower than the lowest hourly average O₂ concentration measured during the most recent CO performance test.  This minimum O₂ concentration is then established as the set point for the O₂ trim system. The facility must continuously operate the boiler at or above this set point. If a facility chooses to comply with this option, then O₂ content is not required to be monitored on a 30-day rolling average.  The facility must monitor the O₂ trim set point and whether the O₂ trim controller is in automatic or manual mode of operation.

For boilers that operate a CO CEMS to comply with the alternative CO CEMS emissions standard, the O₂ operating limit does not apply.  Another option may be to use an existing CEMS that measures O₂ for another requirement, such as an existing nitrogen oxides (NO_X) CEMs that is being used for compliance with 40 CFR Part 60, Subpart Db.  Based upon U.S. EPA guidance, a facility can use O₂ measurements from an existing CEMS in the stack to satisfy the O₂ monitoring requirement.  U.S. EPA also advised that the wording “at the outlet of the boiler” in 40 CFR §63.7525(a)(1) would include the stack. Similar to the option mentioned above, the facility would continuously monitor O₂ content from the CEMS and reduce the data to 30-day rolling averages.  The 30-day rolling average would have to be maintained at or above the lowest hourly average measured during the most recent CO performance test.

No matter which option is chosen, the O₂ monitoring procedures must be documented in the site specific monitoring plan (SSMP).  The SSMP must be prepared according to the requirements in 40 CFR §63.7505(d)(1) through (4).  For O₂ monitoring, the SSMP must include installation and ongoing quality assurance requirements.

If you have questions regarding your O₂ option, feel free to give me a call at (334) 855-3382 or reach out to me via email at sbowden@all4inc.com.

The Shoe Has Dropped But Most Companies Don’t Know It – It’s Called PADEP RACT 2

About 400 facilities in Pennsylvania probably don’t know they have been given a New Year delivery even before the dropping of the ball in Times Square.  The delivery is not a bundle of joy brought in by a stork, it’s a count-down clock and it’s already ticking.  That is the Pennsylvania Department of Environmental Protection (PADEP) Reasonably Available Control Technology regulations for existing major facilities to assess whether they need to install additional air emission controls or implement additional work practice measures to reduce emissions of volatile organic compounds (VOC) and nitrogen oxides (NO_X).  These new “RACT 2” regulations have completed the most critical approval steps and are essentially now being processed through the final administrative steps before publication as final, possibly as late as March of next year.  However, the final compliance date for the regulations, as mandated by U.S. EPA, has been set as January 1, 2017.  RACT is a federal requirement resulting from the fact that Pennsylvania is in the Northeast Ozone Transport Region (OTR) and therefore, Pennsylvania has an obligation under the federal Clean Air Act (CAA) to require this control technology assessment.

A common question posed by affected facilities is “Do I have to submit anything to PADEP if my facility is in compliance”?  The short answer is “No”.  So, where is the problem?  A large number of source types have specific presumptive emission limits provided in this new regulation.  If you know that your affected emissions units already meet those limits (and that is a big IF), you can wait until PADEP knocks on your door (sometime after January 1, 2017) and asks you to provide proof of compliance.  Well, “waiting” is probably not something that you will want to do.  First and foremost, you will need to gather recent testing or source monitoring data (i.e., continuous emissions monitoring system (CEMS) data) that proves you are in compliance.  Second, if your sources are not in compliance, or if there is no presumptive RACT 2 limit specified for your source, you have six (6) months from final publication of the regulations to figure that out, prove why controls are not “reasonable”, submit a plan with a proposed RACT limit, or submit a Plan Approval application to install controls. Six months from now to figure all this out may seem like a lot of time, but it isn’t since you will likely  need to evaluate actual emission rates (i.e. stack testing), provided you do not have a CEMS.

Some of the new presumptive emission limits, especially for natural gas fired boilers and process heaters, are very tight.  Some companies that installed new low-NO_X burners under the previous RACT regulations from the 1990’s could be challenged to meet the new limits.  So don’t assume you don’t have any problems because you are burning natural gas, a “clean fuel”.  Also note that “reasonably available” controls are in the eye of the beholder, which includes not only PADEP but the U.S. EPA, other state agencies, local regulatory authorities (e.g., Philadelphia and Allegheny County), and third party non-governmental organizations (NGOs).  Now is the time to be in action; before those sugar plums come dancing and the champagne rings in the New Year.  Want to find out more about RACT 2, give me a call, John Slade, Senior Consultant for All4 at 717.822.0009, or call Ron Harding, Project Manager, at 610.933.5246 extension 119.

Meteorological Monitoring Requirements of the Petroleum Refinery Rule

The Petroleum Refinery Rule Package was published in the Federal Register on December 1, 2015 officially starting the two (2) year process of preparing for and implementing the 40 CFR Part 63 Subpart CC benzene fenceline monitoring (BFM) requirements so that your refinery is in compliance on February 1, 2018.  One (1) specific BFM requirement included as part of the 40 CFR Part 63, Subpart CC is the collection of hourly meteorological data.  Many refineries may be located near a major airport that operates a U.S Weather Service (USWS) station and/or currently has an onsite meteorological monitoring system.  However, there are a few nuances to the final rule that need to be understood to determine if either of these sources of meteorological data meet the requirements of the rule.

Specifically, 40 CFR Part 63.658(d) requires refineries to collect and record hourly average temperature, barometric pressure, wind speed, and wind direction meteorological data.  Refineries that utilize a near-field source correction or an alternative test method that provides time-resolved measurements are required to use an on-site meteorological system in accordance with Section 8.3 of Method 325A.  Refineries not utilizing near-field correction or alternative test methods may utilize USWS meteorological stations within 40 kilometers.

Refineries that currently have an on-site meteorological monitoring station and are planning on utilizing the data to meet the BFM requirements may need to take a closer look at their existing meteorological monitoring systems.  40 CFR Part 63.14 incorporates U.S. EPA’s “Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements Version 2.0” (QA Handbook) by reference.  The QA Handbook summarizes calibration and standardization procedures and requires meteorological monitoring systems to be audited semi-annually.  Unfortunately many pre-packaged meteorological monitoring systems were not designed with the calibration procedures outlined in the QA Handbook in mind and are not able to be calibrated.  In addition the QA Handbook outlines criteria for siting a meteorological monitoring systems and minimum sensor resolution and accuracy criteria that will have to be met to utilize the meteorological data for the BFM requirements.

For refineries that are able to utilize USWS data, it is in your best interest to evaluate the USWS station to determine if it is representative of the conditions at your refinery.  The evaluation would be very similar to the representativeness analysis required as part of air quality modeling demonstrations for Prevention of Significant Deterioration permitting.  Some things to consider include:

• Distance,
• Differences in base elevations,
• Significant topographic features between your refinery and the USWS station,
• Proximity to large bodies of water, and
• Differences is land use patterns.

These are all items that will influence meteorological data between your refinery and the meteorological data you may want to utilize at a USWS station.  When considering whether to utilize USWS station or an on onsite meteorological monitoring system for meteorological data there are some additional items to consider.

• Operational control of an onsite meteorological monitoring system vs. relying on USWS station,
• Differences in Quality Assurance (QA) objectives between onsite meteorological monitoring and USWS station, and
• Availability shorter averaging periods from USWS [currently 1-minute and 5-minute average wind speed and direction is available monthly from the National Climatic Data Center (NCDC)].

For assistance evaluating your existing on-site meteorological monitoring system and/or evaluating USWS station to meet the fenceline benzene monitoring requirements please contact Dan Dix at ddix@all4inc.com or 610.933.5246 x118.

More Residual Risk Review Activity for Hazardous Air Pollutants (HAPs) on the Horizon

What’s the Issue?

Earlier this year, a coalition of environmental groups sued U.S. EPA for failing to implement the residual risk and technology review (RTR) process for National Emission Standards for Hazardous Air Pollutants  (NESHAP), commonly referred to as Maximum Achievable Control Technology (MACT), standards for numerous source categories.  Under the Clean Air Act (CAA), U.S. EPA must revisit these initial MACT standards after they are implemented and see if additional requirements are needed to address “residual risks” that remain.  ALL4’s 4 The Record article posted in August 2014 provides more detail on the process for developing residual risk standards.

What’s the Schedule?

U.S. EPA is years behind the RTR review schedule required by the CAA.  As often happens, environmental groups have sued U.S. EPA to force the agency to commit to a schedule for taking action.  This particular lawsuit specifically cites 21 source categories that should have been reviewed by as early as 2011.  The 21 source categories cover a wide range of industrial categories including: surface coating of automobiles and light-duty trucks (Subpart IIII), miscellaneous metal parts and products (Subpart MMMM) and plastic parts and products (Subpart PPPP), municipal solid waste landfills (Subpart AAAA), and ethylene production (Subparts UU, XX, YY).  A copy of the lawsuit with a complete list of the 21 source categories can be found here.

U.S. EPA is currently negotiating a settlement with the environmental groups in which U.S. EPA would agree to a specific schedule to complete its RTR review.  Once this settlement (i.e., consent decree) becomes final, which is expected in the next couple of months, the clock will start ticking on U.S. EPA as well as the 21 source categories covered under the settlement.

What Can You Do?

There’s action companies can take now to prepare to work with U.S. EPA on these residual risk standards.  It’s critical for companies to be proactive and be at the table with U.S. EPA while standards are developed rather than rolling the dice and seeing whether their facilities can meet the final rules after they come out!  When the original MACT standards were issued, I was a consultant for various clients who were affected by multiple MACT standards.  Along with my colleagues, we helped our clients individually and through trade associations to work with U.S. EPA.  This proactive regulatory advocacy was critical in having U.S. EPA set MACT standards that met the CAA requirements while still providing as much operational flexibility to our clients as possible.

Need help to evaluate what you can do now about the residual risk standards on the horizon?  Feel free to send me an email at rcheng@all4inc.com, comment below or give me a call at 571-392-2593.

Time to Upgrade Your Facility’s Data Management System?

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Are you worried about your compliance approach using data collected from continuous monitoring systems (CMS) at your facility?  Or maybe the inefficiencies in your process you currently use for managing your data cause you to periodically lose sleep.  It is only a matter of time before someone (i.e., a regulator) starts asking questions about your CMS data whether it is in response to reports submitted to regulatory agencies or as part of an internal or third-party audit.  One (1) solution is to get that data under control and to fully understand how compliance with your emissions limits is demonstrated by your CMS.  Maybe it is time to install a new, or upgrade an existing, data acquisition system (DAS) to manage measured data from CMS at your facility.  A DAS manages your CMS compliance data from collection, validation, and calculation, through notification, recordkeeping, and reporting.  To get the most out of a DAS, your (and your facility’s) involvement needs to go far beyond the selection of the DAS software or vendor.  It requires the dedication of resources to properly implement and integrate the DAS into your facility’s compliance solution.  A properly selected, integrated, and implemented DAS can make you wonder how you ever got by without a DAS (or if upgrading an existing DAS, how you ever were able to confidently assess your facility’s compliance status with the previous DAS).  One (1) of the most important roles of a DAS is to serve as a tool to enable you to assess your facility’s compliance status with the various environmental regulations where compliance is demonstrated using a CMS.  Another important role of the DAS is to generate reports from a database containing CMS data that can withstand scrutiny from regulatory agencies, internal or third-party auditors, environmental groups, or anyone else that may be accessing and reviewing your data in the public domain.

So you have come to the sobering conclusion that there is now way too much CMS data collected at your facility to handle with your current system and you will not be able to survive without a new or upgraded DAS.  Why not implement a DAS that integrates into your existing systems and provides an increased efficiency for managing your compliance data?  Outside of the data management piece, one (1) of the most important aspects of a DAS is that it provides a platform for delegation and accountability.  In a typical facility structure, the Instrumentation, Operation, and Environmental Departments all serve important roles in the generation and utilization of CMS data for compliance demonstrations.  The Instrumentation Department is responsible for providing quality-assured data from the CMS and minimizing CMS downtime.  The Operation Department is responsible for considering CMS data while operating sources within regulatory parameters and implementing corrective actions when a regulatory parameter is exceeded.  The Environmental Department is responsible for overseeing the systems, including the DAS, used by the Instrumentation and Operation Department to fulfill their responsibilities.  A DAS that is fully implemented should provide the means for the Environmental Department to delegate the responsibility of CMS downtime to the Instrumentation Departments and the deviations or excess emissions to the Operation Departments.

Because the Environmental Department typically is responsible for supplying the tools needed for the Instrumentation and Operation Departments to do their jobs, it is important that the DAS is fully implemented and integrated into the facility’s existing system.  Let’s ask ourselves several questions to better understand how to pull all of the pieces together to provide a compliance solution that gives you, the Environmental Manager, confidence and makes the job of the Environmental Department clearly defined and more efficient.

How do you manage your CMS compliance data now?

Let’s start with an honest assessment of your current DAS (or lack thereof) and data management systems to highlight inefficiencies (and possible regulatory exposures).  Are there aspects of the management of your compliance data keeping you up at night?  Or maybe you have inherited a legacy system and you just do not know how it works.  Could you explain to a third party or the person certifying compliance at your facility how compliance averages are built?  If you have a DAS, request a specification from the vendor that summarizes how the data are validated, expressed in terms of the emissions standard, and averaged for purposes of demonstrating compliance.  If you have an in-house data management solution, find “that person” at your facility who can tell you how the data are handled.  Questions to be thinking about are: how are invalid data (e.g., in calibration, in maintenance, out-of-control, etc.) handled; how data collected when the unit is offline are considered when building compliance averages; how are compliance averages built and validated.  Let us not forget the regulatory references for the basis by which the data management process was selected.  You might be surprised what you find out about your data management system and what it is (and isn’t) doing through the assessment process.

What considerations are made when integrating a DAS at your facility?

A DAS is your compliance engine, period.  Calculations and data validation should be completed in the DAS and sent to other “systems” at your facility.  Compliance averages should never be calculated in more than one (1) place!  This will only lead to discrepancies and related issues as existing regulations are clarified or new ones added.  Not to mention that these “other” systems were most likely not designed to valid and calculate averages consistent with the regulatory requirements.  Your resources are better spent validating one (1) robust compliance engine and using that tool to push the results to “other” systems such as Distributed Control Systems (DCS), PI Historians, or Environmental Management Systems (EMS).  Please note that fitting a DAS into your current data management system could have complications and must be considered as part of the DAS implementation process.  For example:

• What other parameters do you need to express in terms of the emissions standard?
• How do you assign unit operational status?
• Where do the data come from?
• Where does it need to go?
• Are the associated connecting “systems” compatible?

What will your future DAS needs include?

One (1) guarantee is that your future monitoring needs will only increase and that reporting will continue to become more electronic in nature requiring the DAS to generate specific-types (i.e., .xml) for direct upload to the regulatory agencies [e.g., U.S. EPA’s Electronic Reporting Tool (ERT), etc.].  How will your DAS (and vendor) track and anticipate these future needs?  How can future sources, monitoring parameters, and reports be added to the DAS?  You will need to ensure that a new or upgraded DAS will be able to provide future compliance solutions.  You will need to challenge your DAS vendor on what their future concerns are, how they are tracking and addressing an evolving regulatory and monitoring climate, and most importantly how your vendor will keep you apprised of and compliant with upcoming changes.

What type of DAS do you need?

At first glance, your DAS needs can be dictated by what regulations you are required to demonstrate compliance with.  Nowadays, DAS are effective tools that do far more than just calculate and validate compliance averages.  Your DAS can also be used to manage routine (but tedious) quality assurance and related activities (e.g., cylinder gas audits, linearity checks, relative accuracy test audits, manage calibration gases, generate regulatory specific reports).  DAS vendors are constantly adding “bells and whistles” to set their product apart to provide a tool that can also increase productivity.  Whether it is a CMS downtime or excess emission event, the DAS must also have notification capabilities.  It is not uncommon for a DAS to generate alarms that are transmitted via email or text notifying the proper parties of an event.  While it is great that the notification capabilities of a DAS can trigger responses from the appropriate facility personnel, the actions taken may be reliant on other systems at the facility.

What other resources do I need when implementing a DAS?

The implementation of a DAS can have a domino effect on other systems at your facility.  In the long run the identification of weaknesses in supporting systems will result in an overall stronger compliance solution. However, if the transition is not appropriately planned for, the fallout can be overwhelming.  Sometimes, weaknesses in supporting systems can cause the implementation of a DAS to slow down or stop all together while these systems are addressed.  In other cases, the Environmental Department may manually fill in the gaps, thereby preventing the final delegation on certain activities.  For example, the DAS provides the means for data quality responsibilities to be delegated to the Instrumentation Department.  Imagine that a DAS notifies the Instrumentation Technicians that a CMS is not generating quality assured data.  The Instrument Technician springs into action, repairs the CMS, and returns it to service.  What’s next? Do any additional quality assurance activities (i.e., calibration, cylinder gas audit) need to be completed?  What does the CMS Quality Control/Quality Assurance (QA/QC) Plan require, if anything? Do you even have a QA/QC Plan, or a site-specific monitoring plan for a MACT standard? The point is that the QA/QC Program will most likely need to be revised to complement the DAS platform.

After the Instrument Technician completes all of the required activities, he/she now acknowledges the alarm triggered by the DAS in order for the CMS downtime report(s) to be completed “real-time” as the events happen (or shortly thereafter once the issue is resolved).  How does the technician know how to categorize the event when acknowledging the alarm in the DAS?  How was the technician trained?  Typically, additional training will also be required for all parties, including Instrumentation Technicians, to get the most out of your DAS.  At the end, when all the systems fit together your DAS will become an asset to your compliance solution.

Even though we only highlighted a few questions to consider, there are many more aspects to identify and work through when fully implementing a DAS.  Remember that implementing a DAS is a major commitment of facility resources that will extend (and if properly implemented will provide benefits) beyond the Environmental Department.  The effort to implement a DAS will also extend far beyond the hardware and software pieces and challenge “other” systems that may be already fully functional.  However, once fully implemented it can provide a compliance tool that can minimize your regulatory exposure while saving time.  Understanding the entire process, and anticipating the issues that will arise, allows for a more successful implementation of a DAS.  For more information on the process by which DAS are implemented, please feel free to call at 610.933.5246 ext. 117 or email me at eswisher@all4inc.com.

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Updated: U.S. EPA Issues Long-Awaited Petroleum Refinery Rule Package

UPDATE (12/2/15): The Petroleum Refinery Rule Package was published in the Federal Register on December 1, 2015.  The publication establishes a February 1, 2016 effective date.  

ORIGINAL (9/30/15): On September 29, 2015, U.S. EPA issued the long-awaited Petroleum Refinery Rule Package.  After considering more than 200,000 comments on the June 2014 proposed rule package, U.S. EPA issued the final revisions to the Maximum Achievable Control Technology (MACT) and New Source Performance Standards (NSPS) Refinery Air Rules (i.e., 40 CFR Part 63, Subparts CC and UUU, Refinery MACT 1 and Refinery MACT 2; and, 40 CFR Part 60, Subparts J and Ja, respectively).  The final package encompasses the risk and technology review (RTR) of Refinery MACT 1 and MACT 2.  Additionally, it provides technical corrections and clarifications for the 2008 NSPS.   

Today’s blog focuses on the major changes from the proposed rules.  For more information on the proposed rules, please refer to my previous blog: U.S. EPA Proposes Overdue Refinery Air Rules, as well as ALL4’s May 2014 and June 2014 4 The Record articles for more in-depth looks at flare requirements, benzene fenceline monitoring, and related requirements.  In addition, please refer to John Slade‘s blog post about Refinery MACT risk assessment. 

So, what changed and what stayed the same from the proposal? 

Let’s get started with benzene fenceline monitoring, jump into flare combustion efficiency requirements, discuss delayed coking units (DCU), and wrap things up with everyone’s favorite, Startup, Shutdown and Malfunction (SSM). 

Benzene Fenceline Monitoring

For the most part, the benzene fenceline monitoring requirements remain the same as the proposal.  The key differences include imposing a tighter implementation schedule [reduced from three (3) years to two (2) years after promulgation].  U.S. EPA specifies alternative monitoring technologies as part of the final rule and clarifies monitor siting and analytical procedures.  U.S EPA now requires reporting on a quarterly basis rather than semiannual.  Additionally, U.S. EPA provides an incentive for reducing fugitive emissions by providing an option to decrease sampling locations for remaining consistently 10% below the benzene fenceline concentration trigger.  UPDATE (12/2/15): Please see our blog, “Refinery MACT – Final Benzene Fenceline Monitoring Provisions” for more details.

Flare Combustion Efficiency

U.S. EPA’s flare operating requirements maintain the emissions reductions projected in the proposal; however, the compliance approach is streamlined.  U.S. EPA is allowing refineries to use a higher adjusted heating value as long as the refinery has a hydrogen monitoring system.  Refineries can choose between a 15-minute feed forward or a 15-minute block average for compliance demonstration purposes.  The requirements are also simplified to a single net heating value operating limit in the flare combustion zone of greater than or equal to 270 British Thermal Units per standard cubic foot (BTU/SCF).   Refineries also are allowed to use limited sampling to demonstrate compliance for non-variable flare gas compositions.  UPDATE (12/2/15): Our blog, “Finalized Refinery Rule – Flare Edition” summarizes the provisions in the proposed rule and the finalized refinery rule. 

DCU

The majority of the DCU requirements remain the same as the proposal with some additional flexibility.  The final rule allows for averaging across all DCU at a facility to meet the 2 pounds per square inch gauge (psig) requirement.  For new sources, a 2.0 psig (on a per-coking cycle basis) MACT floor is established and does not allow for facility-wide coke drum averaging.  Additionally, U.S. EPA took into account cost data provided by commenters, as well as revised DCU emissions (resulting from revised emission factors) in the final rule. 

SSM

In the proposed rule, refineries were required to comply at all times, as the SSM exemptions were removed.  In the final rule, U.S. EPA establishes work practice standards for pressure relief devices (PRDs) and emergency flaring that include proactive requirements (e.g., instrumentation, operator training, improved process control) and root cause analysis along with corrective action.  Additionally, U.S. EPA’s final rule will require refineries to make operational changes to prevent PRD releases and emergency flaring.  This approach is in lieu of building additional flares to control releases. 

Promulgation of the rule can be expected in the Federal Register in the coming weeks or month.  Upon promulgation, refineries have three (3) years to demonstrate compliance with the rule, with a few exceptions, including the 2-year requirement for benzene fenceline monitoring implementation.

Stay tuned to future ALL4 4 The Record articles where we’ll provide an in-depth analysis of some of the key requirements of the final rule and the impacts on refineries.

Final 2015 Revisions to the GHG Reporting Rule for the Oil and Gas Sector

On October 22, 2015, U.S. EPA issued final amendments to 40 CFR Part 98, Subpart W (Mandatory Greenhouse Gas (GHG) Reporting for Petroleum and Natural Gas Systems).  The amendments – which were proposed on December 9, 2014 – require GHG emissions reporting for several sources that had not previously been included in Subpart W.  The new sources include gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations.  The revisions also include the addition of well identification reporting requirements for certain facilities.  Finally, confidentiality determinations were finalized for new data elements in the amendments.

The major amendments to 40 CFR Part 98, Subpart W include the following:

• The addition of two new industry segments:
  • Onshore Petroleum and Natural Gas Gathering and Boosting segment:
    • Includes GHG emissions from equipment such as acid gas removal units, storage tanks, blowdown vents, dehydrators, equipment leaks, flare stacks, and pneumatic devices.
  • Onshore Natural Gas Transmission Pipeline:
    • Includes GHG emissions from blowdowns of natural gas pipelines between compressor stations.
• Changes for the existing Onshore Petroleum and Natural Gas Production segment:
  • Completions and workovers of oil wells with hydraulic fracturing are now included.
  • Well identification numbers associated with individual oil and gas wells are required to be reported.
• Best Available Monitoring Methods (BAMM) are allowed only for reporting year 2016 on a short-term transitional basis for the facilities new to reporting under Subpart W and facilities subject to new monitoring requirements as a result of these amendments.  Beginning January 1, 2017, reporters must discontinue use of BAMM and follow all applicable monitoring and QA/QC requirements of Subpart W.
• The U.S. EPA is required to make information obtained under section 114 available to the public, except for information that qualifies for confidential treatment. The U.S. EPA has determined that this action is subject to the confidential treatment provisions and has finalized the confidentiality determinations as proposed.  More specific information can be found on Page 18 of the Federal Register.

In addition, the following are two (2) responses from the U.S. EPA to take note of:

• The U.S. EPA has not changed the definition of “gas well” or “oil well.”  Rather, reporting of GHG emissions are required from completions and workovers with hydraulic fracturing for wells in the Onshore Petroleum and Natural Gas Production segment, regardless of whether the primary product is oil or natural gas.
• The U.S. EPA is assessing the potential opportunities for application of remote sensing technologies and other innovations in measurement or monitoring technology.  Provisions related to advanced measurement or monitoring methods are not addressed in this rule and the U.S. EPA has not responded to comments regarding advanced measurement or monitoring methods in this rulemaking. Instead, following review of the data and information received in comments, the U.S. EPA may propose amendments related to the use of innovative technologies in reporting to the Greenhouse Gas Reporting Program (GHGRP) in a future rulemaking.

These amendments are effective January 1, 2016 and will come into play for the 2016 calendar year.  The annual reports due March 31, 2016 will not have to implement these amendments, but reporters will have to begin monitoring, recordkeeping, and calculating emissions in accordance with the amendments beginning January 1, 2016.  The first reports to be submitted using the amended requirements will be those submitted March 31, 2017, covering the reporting year 2016.

If you have any specific questions, feel free to reach out to JP Kleinle at jkleinle@all4inc.com or myself at mstroup@all4inc.com.

Cross-State Air Pollution Rule (CSAPR) Update

On November 16, 2015, the United States Environmental Protection Agency (U.S. EPA) proposed the Cross-State Air Pollution Rule (CSAPR) Update.  According to U.S. EPA, the proposed rule will affect 3,047 electric generating units at 913 coal-, gas-, and oil-fired facilities in 23 states (see figure below).

Alabama, Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, West Virginia, Wisconsin

Background

U.S. EPA promulgated the original CSAPR on July 6, 2011 to address the interstate transport of ozone under the 1997 ozone national ambient air quality standards (NAAQS) and particulate matter less than 2.5 microns (PM_2.5) under the 1997 and 2006 NAAQS. CSAPR is a “cap and trade” program to reduce nitrogen oxides (NO_X) and sulfur dioxide (SO₂) emissions from power plants that contribute to interstate ozone and particulate pollution.  CSAPR was designed to replace the 2005 transport rule known as the Clean Air Interstate Rule (CAIR) which was also a NOx and SO2 trading program.  CSAPR then underwent three (3) years of litigation, briefly summarized below.  

• December 30, 2011 – the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued its ruling to stay CSAPR pending judicial review. 
•  January 10, 2012 – the U.S. EPA reverted back to the approved Clean Air Interstate Rule (CAIR) allowances until a decision on CSAPR could be finalized. 
•  January 24, 2013 – the U.S. Supreme Court granted U.S. EPA’s petition to review the 2011 D.C. Circuit’s opinion on CSAPR. 
•  April 29, 2014 – the U.S. Supreme Court reversed the 2011 D.C. Circuit’s opinion vacating CSAPR. 
•  October 23, 2014 – the U.S Court of Appeals for the D.C. Circuit ordered that U.S. EPA’s motion to lift the stay of CSAPR be granted. 

In a separate litigation (EME Homer City Generation, L.P. v. Environmental Protection Agency), the U.S. Court of Appeals for the D.C. Circuit in their July 28, 2015 decision, held invalid the ozone-season NO_X budgets and remanded without vacatur to U.S. EPA for it to reconsider those emissions budgets. 

Summary of CSAPR Update

The CSAPR Update is in direct response to the D.C Circuit Court’s July 28, 2015 remand to reconsider the NO_X emission budgets; it is also intended to address the lower 2008 NAAQS (75 parts per billion (ppb) versus the 1997 NAAQS of 80 ppb).  As such, the proposed CSAPR Update contains significant reductions in NO_X Ozone Trading Budgets for 2017 and thereafter (see summary table here) for many of the 23 states involved.  Please note that the CSAPR Update intends to remove Florida and South Carolina from the program.  

Next Steps

States may implement the new standards in their own state implementation plan (SIP) or chose to follow the federal implementation plan (FIP) proposed by U.S. EPA.  Either way, reductions will be needed for many states, so now is your chance to comment.  Once published in the Federal Register, U.S. EPA will accept comments for 45 days.  There will also be a public hearing on the matter on December 17, 2017, in Washington, D.C.