May 2012 - ALL4

More NAAQS News – This Time Ozone

On March 27, 2008, U.S. EPA revised the National Ambient Air Quality Standard (NAAQS) pertaining to ozone from a maximum 8-hour average concentration of 84 parts per billion (ppb) to 75 ppb. Although U.S. EPA has since initiated a rulemaking to reconsider the new 75 ppb NAAQS, there has been no revision or revocation of the standard. U.S. EPA is designating 45 areas as nonattainment, one area as unclassifiable, and the remaining areas as unclassifiable/attainment with respect to the 75 ppb NAAQS level. The designation of nonattainment also has sub-designations: Marginal, Moderate, Serious, Severe, and Extreme. Air quality permitting requirements for new sources and modifications to existing sources in ozone nonattainment areas are determined, in part, by this classification. U.S. EPA issued a final rule on May 21, 2012 that established the air quality thresholds that define each of the five nonattainment sub-designations listed above, established the attainment deadline associated with each classification, and granted all requested and supported reclassifications. At the time the previous ozone NAAQS was finalized (1997), there were 113 nonattainment areas nationwide. Currently there are only 45 nonattainment areas as designated by the 2008 NAAQS. A map of these areas can be found here.

The air quality planning requirements, as mentioned above, are dependent on the nonattainment classification. The closer that an area is to attaining the NAAQS, the less stringent the mandatory planning and permitting requirements. As the design values increase above the ozone NAAQS level, the emissions controls and New Source Review (NSR) offset requirements become more stringent. The NSR offset requirements describe a system in which certain emissions increases of VOCs and NO_X must be “offset” by at least the same amount of decreases from another source within the region. The offset requirement, coupled with the Lowest Achievable Emission Rate (LAER) control technology requirements for those pollutants, is intended to move ozone nonattainment areas into an attainment designation. The nonattainment classifications are as follows:

Marginal: 76 – 86 ppb
Moderate: 86 – 100 ppb
Serious: 100 – 113 ppb
Severe: 113 – 175 ppb
Extreme: 119- 175 ppb

All values listed above correspond to 8-hour averages. The upper limit of each classification is non-inclusive.

Marginal ozone nonattainment areas will be allotted three (3) years after December 31 of this year to achieve attainment, and the “higher” the degree of nonattainment, the more time that will be allotted to achieve attainment. This approach allows for even the lowest classification of nonattainment areas to have three full ozone seasons, which generally run through late spring, summer, and early fall, in order to attain the NAAQS. Following are the attainment deadlines for each classification:

Marginal: December 31, 2015
Moderate: December 31, 2018
Serious: December 31, 2021
Severe: December 31, 2027
Extreme: December 31, 2032

ALL4 will continue to monitor the current review of the 75 ppb ozone NAAQS to see where the standard is inevitably set. The previous ozone NAAQS review that was withdrawn by presidential order was targeting a NAAQS level as low as 65 ppb. If a 65 ppb level were to be set, existing nonattainment areas would grow and a new timeline for implementation of state programs to achieve attainment would be put in place.

Hide and Seek? Final Revisions to 40 CFR Part 60 Subparts D, Da, Db, and Dc Promulgated “Under” MATS Rule

On February 16, 2012, U.S. EPA finalized the National Emission Standards for Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility Steam Generating Units (EGUs) under Part 63, Subpart UUUUU, otherwise known as the Mercury and Air Toxics (MATS) rule. In that same action, but under the radar, the U.S. EPA also finalized several revisions to the Standards of Performance for New Stationary Sources (NSPS) under Part 60, not only for EGUs under Standards of Performance for Fossil-Fuel-Fired Electric Utility, but also for Industrial, Commercial, Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units. More specifically, multiple revisions were made to 40 CFR Part 60 Subparts D, Da, Db, and Dc in the shadow of the promulgation of the MATS rule. The primary changes to the NSPS rules were related to Subpart Da and included revised standards for sulfur dioxide (SO2), nitrogen oxides (NOX), and particulate matter (PM). The history of the changes the NSPS rules dates back to U.S. EPA’s promulgated amendments to 40 CFR Part 60 Subparts D and Da in February 2006. In September of 2009, U.S. EPA was granted a voluntary remand (without vacatur) for the 2006 amendments as a result of a suit filed by states and non-governmental organizations (NGOs) in April 2006 (New York v. Environmental Protection Agency, No. 06-1148). The suit alleged that:

The SO2 and NOX standards established by U.S. EPA in the amendments did not represent the best system of emission reductions (BSER).
The amendments failed to establish emission limits for fine particulate matter (PM2.5) and condensable particulate matter.
The amendments did not reflect emissions limitations achievable by integrated gasification combined cycle (IGCC) technology.

U.S. EPA’s position that it lacked legal authority to regulate greenhouse gases (GHG) from stationary sources was also challenged in the suit as well as its failure to adopt carbon dioxide (CO2) emissions standards for power plants.

On May 3, 2011 and simultaneously with the MATS rule, U.S. EPA proposed amendments to Subparts D and Da in response to the vacatur and at the same time proposed multiple minor amendments, clarifications, and corrections to Subparts D, Da, Db, and Dc. While the changes to Subpart Da were discussed in the preamble to the February 16, 2012 promulgation, various additional amendments to 40 CFR Part 60 Subparts D, Da, Db, and Dc were not specifically discussed in the final rule preamble and received little, if any, fanfare. In fact, the preamble to the final rule advises readers to “See the Response to Comments document” to learn about the additional amendments. The preamble to the proposed rule, which appeared in the Federal Register on May 3, 2011 (with the proposed MATS rule) characterized the additional proposed NSPS amendments as intended to “… clarify the intent of the current requirements, correct inaccuracies, and correct oversights in previous versions that were promulgated.” It’s time to take a closer look at the amendments.

Subpart D applies to fossil-fuel-fired steam generating units and of more than 250 million British thermal units per hour (MMBtu/hr) and fossil-fuel/wood-residue-fired steam generating units capable of firing fossil fuel at a heat input rate of more than 250 MMBtu/hr that commenced construction or modification after August 17, 1971. The changes to Subpart D in general include:

A definition for “natural gas.”
Exemptions from particulate matter standards for units that fire only natural gas and units that fire low sulfur liquid fossil fuel (with no post-combustion SO2 control).
A recognition that the use of PM continuous emission monitoring systems (CEMS), bag leak detection systems (BLDS), and a predictive PM model for electrostatic precipitators (ESPs) are acceptable alternatives to continuous opacity monitoring systems (COMS).
For applicable facilities, a requirement to conduct opacity monitoring within 45 days of the next day that fuel with an opacity standard is combusted.
Provides an exemption from COMS requirement for units using PM continuous parametric monitoring systems under 40 CFR Part 63, Subpart UUUUU (MATS rule).

Subpart Da applies to electric utility steam generating units (EGUs) that are capable of combusting more than 250 MMBtu/hr heat input of fossil fuel (either alone or in combination with any other fuel) for which construction, modification, or reconstruction is commenced after September 18, 1978. Integrated gasification combined cycle electric utility steam generating units (IGCC) are subject to Subpart Da (and are not subject to Subpart GG or KKKK) if the IGCC is capable of combusting more than 250 MMBtu/hr heat input of fossil fuel (either alone or in combination with any other fuel) in the combustion turbine engine and associated heat recovery steam generator, and the unit commenced construction, modification, or reconstruction after February 28, 2005. The changes to Subpart Da are sufficiently extensive to warrant a separate analysis in a future edition of 4 The Record. However, a brief summary of the highlights from the final rule are provided below:

Multiple new definitions for “affirmative defense”, “natural gas”, “net energy output”, “out of control periods”, and “petroleum coke.”
A new definition of “gross energy output” for affected units (including combined heat and power units and IGCC units).
Several revised definitions including “petroleum” and “steam generating unit” and deletion of several definitions that are no longer used in the standard.
For new and reconstructed EGUs (i.e., post May 3, 2011), a new fuel-neutral filterable PM standard (versus the originally proposed total filterable plus condensable standard) expressed on an energy output basis and a new PM limit for modified EGUs.
Exemptions from particulate matter standards for units that fire only natural gas and units that fire low sulfur liquid fossil fuel (with no post-combustion SO2 control).
For new and reconstructed EGUs, a new fuel-neutral SO2 emission limit expressed on an energy output basis or 97 percent reduction and a new SO2 emission limit for modified EGUs.
For new and reconstructed EGUs, a new fuel-neutral NOX emission limit expressed on an energy output basis, a new output-based NOX standard for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input), and a new fuel-neutral NOX limit for modified EGUs expressed on an energy output basis.
For new and reconstructed EGUs, a new alternate NOX plus CO combined standard on an energy output basis and a new alternate, output-based NOX plus CO standard for new and reconstructed EGUs that burn over 75 percent coal refuse (by heat input on an annual basis), and a new NOX plus CO output based limit for modified EGUs.
The elimination from Subpart Da of the mercury (Hg) standards and Hg testing and monitoring provisions resulting from the Clean Air Mercury Rule (CAMR).
Exemption from the COMS requirement for units combusting natural gas and/or low sulfur liquid fuels and for facilities equipped with PM continuous parametric monitoring system (CPMS) pursuant to 40 CFR Part 63, Subpart UUUUU.
For applicable facilities, adds a requirement to conduct opacity monitoring within 45 days of the next day that fuel with an opacity standard is combusted.
Clarification that the applicable SO2 and NOX emissions limits apply at all times except during periods of startup, shutdown, or malfunction for units for which construction, modification, or reconstruction commenced before May 4, 2011 and that the applicable SO2, NOx, and NOx plus CO emissions limits apply at all times for units which construction, modification, or reconstruction commenced after May 3, 2011. The applicable PM emission limits and opacity standards under Subpart Da apply at all times except during periods of startup and shutdown.
Addition of affirmative defense and notification provisions in the event of an exceedance during a malfunction.
A requirement to submit relative accuracy test audits (RATA) and performance tests electronically to U.S. EPA through the Electronic Reporting Tool (ERT).
For units for which construction, reconstruction, or modification commenced after May 3, 2011, a requirement to measure condensable PM in conjunction with required filterable PM compliance testing and report results to U.S. EPA (to support future rulemaking?).

Subpart Db generally applies to steam generating units that commence construction, modification, or reconstruction after June 19, 1984, and that have a heat input capacity from fuels combusted in the steam generating unit of greater than 100 MMBtu/hr. The changes to Subpart Db in general include:

An exclusion of temporary boilers from Subpart Db applicability.
A clarification that affected facilities under Subpart BB (Standards of Performance for Kraft Pulp Mills) are subject to the NOX and SO2 standards under subpart Db and the PM standards under Subpart BB.
A revised definition of “distillate oil” to include kerosene, biodiesel, and biodiesel blends.
A new definition of “temporary boiler.”
A requirement to submit relative accuracy test audits (RATA) and performance tests electronically to U.S. EPA through the Electronic Reporting Tool (ERT).
For applicable facilities, adds a requirement to conduct opacity monitoring within 45 days of the next day that fuel with an opacity standard is combusted.
A COMS exemption for facilities using an ESP as the primary PM control device and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section §60.48a.
An exemption from the COMS requirement for units that fire only natural gas and units that fire low sulfur liquid fossil fuel (with no post-combustion SO2 control).

Subpart Dc generally applies to steam generating units for which construction, modification, or reconstruction is commenced after June 9, 1989 and that have a maximum design heat input capacity 100 MMBtu/hr or less, but greater than or equal to 10 MMBtu/hr. The changes to Subpart Dc in general include:

An exclusion of temporary boilers from Subpart Dc applicability.
A specific reference to “fuel heaters” under the applicability section.
A clarification specifying that affected facilities that also meet the applicability requirements under Subpart J or Subpart Ja (Petroleum Refineries) are subject to the PM and NOX standards under Subpart Dc and the SO2 standards under Subpart J or subpart Ja.
A revised definition of “distillate oil” to include kerosene, biodiesel, and biodiesel blends.
A new definition of “temporary boiler”.
A requirement to submit relative accuracy test audits (RATA) and performance tests electronically to U.S. EPA through the Electronic Reporting Tool (ERT).
For applicable facilities, adds a requirement to conduct opacity monitoring within 45 days of the next day that fuel with an opacity standard is combusted.
A recognition that the use of PM continuous emission monitoring systems (CEMS), bag leak detection systems (BLDS), and a predictive PM model for ESPs are acceptable alternatives to continuous opacity monitoring systems (COMS).
An exemption from the COMS requirement for units that fire only natural gas and units that fire low sulfur liquid fossil fuel.

Taken at face value, the revisions to Subpart D, Db, and Dc are largely as indicated by U.S. EPA; that is, they clarify the intent of the current requirements, correct inaccuracies, and correct oversights in previous versions that were promulgated. One potentially complicating factor that is at least indirectly related to the amendments is the general acceptability of PM CEMS “across the board” as an alternative to a COMS. Historically, U.S. EPA would consider alternative monitoring plans (AMP) that include parametric monitoring of control devices for affected units that were controlled by wet scrubbers in lieu of COMS because COMS are not feasible on wet exhaust streams. Now that PM CEMS are at least recognized by each of the “boiler” Subparts, U.S. EPA may defer to PM CEMS instead of parametric monitoring of such units. In fact in a recent decision, U.S. EPA issued a disapproval of a request for an AMP to utilize an alternative opacity monitoring procedure for a boiler that would have used source and control device operating parameters instead of a COMS. U.S. EPA cited the recent revisions to the NSPS under Subpart Db which allows a PM CEMS to be used as an alternative to a COMS and therefore that was the acceptable alternative to a COMS.

As mentioned, the most substantial changes are related to the Subpart Da amendments, which include new fuel-neutral PM, SO2, and NOX standards, on an energy output basis, for new and reconstructed (i.e., post May 2011) units. There is also a new combined NOX plus CO alternate standard (in lieu of the NOX standard) for new and reconstructed units. New standards for modified units are included as well for each pollutant. U.S. EPA’s originally proposed combined PM limit that would have included condensable PM was eliminated due at least partially to concerns regarding the limitations of Method 202. However, a requirement to test for condensable PM during applicable PM compliance testing (via Method 202) remains in the rule. Although almost ancient at this point, all remnants of CAMR have been excised from Subpart Da, along with the associated emission guidelines. Stay tuned to 4 The Record for a more in-depth review of the Subpart Da amendments and their potential impacts.

SO2 NAAQS Stakeholder Workgroups: Party Like It’s 2010

U.S. EPA has set the stage for 1-hour sulfur dioxide (SO₂) NAAQS stakeholder workgroups to be held on May 30, May 31, and June 1, 2012. As discussed in previous blog posts, U.S. EPA has hit the pause button regarding requiring individual facilities to perform SO₂dispersion modeling as part of the 1-hour SO₂NAAQS implementation and designation process. The change in tactics is a result of significant concerns that were expressed by comments on U.S. EPA’s draft dispersion modeling guidance for the SO₂implementation process. With the dispersion modeling aspect of the implementation out of the way for now, U.S. EPA has scheduled stakeholder workgroups to discuss the most appropriate ways to implement the 1-hour SO₂NAAQS, essentially resetting the “Maintenance SIP” aspect of the process to the public comment phase (as there was never an opportunity for public comment in 2010 when the final NAAQS was promulgated). Based on conversations with U.S. EPA, the primary purpose of the industry stakeholder workgroup on July 1, 2012 will be a roundtable discussion on how an enhanced ambient SO₂monitoring network would be implemented. As a primer to the workgroup, U.S. EPA has released a “draft” White Paper outlining a series of specific questions related to the number, location, and practical implications (logistics, costs and who will cover them, etc.) of new ambient SO₂monitors that would be used to develop attainment and nonattainment designations for the 1-hour SO₂NAAQS. U.S. EPA will use the information discussed at the stakeholder group to develop a proposed implementation strategy that will include either an enhanced monitoring network, dispersion modeling, or a combination of both (no, the dispersion modeling requirement is not completely off the table). Also, on a related note, U.S. EPA is still finalizing designations for those areas that already had SO₂ambient monitoring data available.

ALL4 will continue to track the latest developments and will be involved in the May 30 (Washington, DC) and July 1 (Research Triangle Park) stakeholder workgroup. Stay tuned for a 4 The Record article next month describing the results of the workgroup and the next steps in the process.

ALL4’s: Is That Your Final Answer?

Last Month’s Answer and Winner:

Congratulations to Mr. Scott Kirkpatrick of NewPage in Wickliffe, KY who correctly identified the piece of monitoring equipment pictured in April’s “Is That Your Final Answer” question as a sonic anemometer. A sonic anemometer uses sound waves to make meteorological wind speed and wind direction measurements using the Doppler shift (remember the shift in tone of the fire truck siren as it approaches and then passes you, that’s the Doppler shift). We posed this question about meteorological measurements to highlight the fact that meteorological data and air dispersion modeling are destined to play important roles for facilities in the next few years.

Question:

Contrasted against the deliberate nature of last month’s question, this month’s “Is That Your Final Answer” question came to us rather by chance. As some office cleaning was taking place, an aged and yellowed photocopied sheet slipped from the pages of an old text book. On this page we encountered a surprise. For on this sheet were listed the National Ambient Air Quality Standards for criteria pollutants. Now as you know, Section 109 of the Clean Air Act (CAA) requires air quality “criteria” be developed for pollutants that are part of the NAAQS program. Prior to the 1970 CAA, the Department of Health, Education, and Welfare (HEW) took the first initiative at deriving the air quality criteria documents that would serve as the basis for establishing a NAAQS. Today we are very familiar with the six criteria pollutants: fine particulate matter (PM₁₀/PM_2.5), sulfur dioxide (SO₂), nitrogen dioxide (NO₂), ozone (O₃), lead (Pb), and carbon monoxide (CO). However, as shown on the yellowed photocopy from the late 1970s there was a seventh criteria pollutant. The seventh criteria pollutant was not viewed as rigorously as the other six criteria pollutants and was eventually removed. For this month’s “Is That Your Final Answer” question name the seventh criteria pollutant. Hint, total suspended particulate is not the correct answer. Good luck!

Answer:

Please e-mail your answer to final.answer@all4inc.com. Include in the e-mail your name, answer, and address (to receive your prize).

ALL4’s Final Answer is a monthly feature of our Blog Digest. It is designed to test your knowledge across the environmental field, quiz you on the building blocks of air quality rules, stump you on ALL4 general trivia, and challenge you with brain teasers that have perplexed us. The first correct answer e-mailed to us will qualify the respondent for free ALL4 gear and will enter the winner in our end-of-the year “Final Answer Championship.” The subsequent month’s Final Answer will identify the winner and the correct answer from the previous month’s question. You must be an active subscriber of ALL4’s Blog Digest to win a monthly prize and be eligible for the championship prize. ALL4 employees and family members are not eligible to compete. Hope you enjoy this feature and good luck!

“Soft” Engine Certification?

I came across an interesting little tidbit recently during an engine permitting exercise here in Pennsylvania. A facility was seeking air quality permitting for a number of existing emergency generators each driven by a ~3,000 brake horsepower (bhp), diesel fuel-fired, U.S. EPA Tier II certified engine. According to the certification documentation provided by the manufacturer of said engines, the engines are indeed certified to meet the U.S. EPA Tier II emission standards codified at 40 CFR §89.112 (i.e., PM/PM10, CO, and NO_X+HC). However, at their intended operating load (i.e., full standby), the emission profile of the engines is actually higher than the U.S. EPA Tier II emission standard for certain pollutants. Such engines are certified to meet the U.S. EPA Tier II standards via the emission testing procedures of ISO 8178 D2. Without getting into the technical weeds of this specific testing procedure, it appears that the testing procedure prescribes testing engines at various operating loads (i.e., ¼ Standby, ½ Standby, ¾ Standby, Full Standby, and Full Prime). The test data from multiple operating loads is used to determine a weighted emissions average at these various loads for comparison to the U.S. EPA Tier II emission standard. As a result, it would seem that since the tested emissions resulting from ISO 8178 D2 represent a weighted emission average over multiple operating loads, engines certified to meet the U.S. EPA Tier II emission standards can still exceed said standards when operated at specific loads, where such loads result in emissions above the weighted average. ALL4 reminds facilities to keep this in mind when developing air quality permit applications for engine operations so as to navigate this potentially confusing issue carefully.

Browsing the ADI Updates

From time-to-time, U.S. EPA will publish a Federal Register notice announcing updates to the Applicability Determination Index (ADI). The ADI is a searchable database that contains memoranda issued by U.S. EPA on applicability and compliance issues associated with regulations such as Standards of Performance for New Stationary Sources (NSPS), National Emissions Standards for Hazardous Air Pollutants (NESHAP), chlorofluorocarbons (CFC), etc. On May 22, 2012, U.S. EPA announced forty-four new postings to the ADI. It is always prudent to browse the updates to take a quick look to see what the regulated community is “petitioning for” or “seeking clarification of” from U.S. EPA. The ADI update that caught my eye this time was not a recent development, but something to add to my own regulatory library. U.S. EPA is denying alternative monitoring petitions (AMP) for sources with wet scrubbers that propose parametric monitoring in lieu of continuous opacity monitoring systems (COMS) for sources subject 40 CFR 60 Subpart Db. COMS are not effective in moisture saturated exhaust stacks due to the interference of the water droplets with the opacity monitor. For regulations that have a particulate matter (PM) continuous emission monitoring system (CEMS) as an alternative compliance option, such as 40 CFR 60 Subpart Db, it looks like U.S. EPA may require a PM CEMS (which can be installed on “wet stacks”) in lieu of a COMS. Petitions that are submitted to the ADI are handled on a case-by-case basis by U.S. EPA, and you can make your case for a parametric monitoring system. However, it looks like these types of requests may not be approved thereby requiring the installation and certification of costly PM CEMS. The ADI is full of these glimpses of U.S. EPA thoughts that can influence the direction of a project. It is one my first stops when planning a project. The ADI is found at www.epa.gov/compliance/monitoring/programs/caa/adi.html.

Area Source Boiler MACT Reminder

The Area Source Boiler MACT (ASBM) rule became effective on May 20, 2011, with a compliance date of March 21, 2014 for all existing boilers located at area sources of hazardous air pollutant (HAP) emissions. Initial notifications were due on September 17, 2011, and all boilers subject to the rule’s tune-up and work practice standards were required to tune up the boiler by no later than March 21, 2012. If you haven’t tuned up your boiler yet, don’t worry. U.S. EPA issued a No Action Assurance letter on March 13, 2012. The letter states that U.S. EPA will not take enforcement action against anyone who fails to tune up their boiler by March 21, 2012. However, if you failed to submit your initial notification by September 17, 2011, you might find yourself with a Notice of Violation (NOV). ALL4 is aware of a number of facilities that have received NOVs after missing the initial notification deadline.

On December 23, 2011, U.S. EPA published proposed changes to the ASBM in the Federal Register. What changed, you ask? Not much. If adopted, most of the proposed changes consist of clarifications to the rule along with a few new definitions. The proposed changes to the rule will not affect rule applicability. There are now less than two years left to comply with the ASBM rule. ALL4 strongly suggests that facilities that are subject to the ASBM rule take a hard look at the requirements that may affect their boiler operations and to begin planning for compliance.

Your Recipe For a Good Non-Hazardous Secondary Waste Determination

In our last blog we talked about the need to be careful about the “ingredients” that make up the recipe of your alternate fuel so that you can be assured that you are firing a non-waste per the non hazardous secondary materials (NHSM) rule. How well you track your ingredients is part of a NHSM determination demonstration that includes the legitimacy criteria which are specified under 40 CFR Part 241.3(d)(1). Remember, the NHSM determination demonstration is an internal document, but you need to be able to stand behind it should a State or Federal regulatory agency ask to examine it. Earlier this month we promised to give you insight into what a NHSM determination demonstration should look like, so here are our thoughts.

The first component of your NHSM determination demonstration involves confirming that your alternate fuel is “sufficiently processed.” Then you must show that the alternate fuel or the components to the alternate fuel are managed as a valuable commodity. Next, your alternate fuel must have a meaningful heat value (nominally more than 5,000 British Thermal Units – BTU per pound). Finally, you must demonstrate that the contaminant level of the NHSM fuel is comparable to traditional fuels that you are using or could use. Let’s look at each of these four criteria and consider how you could address them.

Step 1 – Clean and Prep Your Ingredients

There are several possible processing operations that you can cite in your NHSM demonstration to meet the definition of processing contained at 40 CFR Part 241.2. The common processing operations are those that remove contaminants, improve the physical fuel characteristics, and increase the energy potential of the NHSM fuel. For many NHSM fuels, a simple description of each step in the material processing phase should suffice in your NHSM determination demonstration. However, if you believe that your NHSM processing would be difficult to qualify under these criteria (i.e., you are only performing shredding), consider preparing a design specification for your NHSM fuel or have your fuel vendor develop the design specification. By establishing a design specification, it means that there are various actions that are occurring to meet the specifications and also that documentation takes place to demonstrate that the NHSM is meeting the specifications. Components to the design specification could include requiring a specific heat content (e.g., Btu/lb), requesting that the NHSM be clean and dry, establishing a particular sizing for the NHSM, requesting that the NHSM be delivered in a certain fashion (e.g., labeled properly in dedicated storage containers), and applying additives to enhance the NHSM (e.g. spraying a surfactant on the material to minimize dusting). Adding these simple operations to a basic shredding process and then documenting that the operations achieve the fuel design specification will assist you to meet the definition of processing as defined at 40 CFR Part 241.2.

Step 2 – Mix Well

Once your documentation for processing the NHSM is established, then you must show that your NHSM is being managed as a valuable commodity. There are two primary considerations related to managing the material. First, you should demonstrate that your NHSM fuel is being managed using the same care as any of your traditional fuels. For example, the NHSM fuel is being stored properly and the product is not being wasted or mishandled. Second, the specifics of your NHSM management should be clearly outlined to show that purchasing price and delivery options of the NHSM are consistent with other conventional fuels that you use.

Step 3 – Pre-Heat

The heat content of you NHSM and its planned usage rate also need to be documented as part of the NHSM determination demonstration. Although the heat content of your NHSM may be part of the design specification, it may be worthwhile to confirm, via testing, the specification on an annual basis or more often if you have reasons to believe that the heat content could vary. By showing how much traditional fuel you intend to replace with your NHSM fuel, you may be able to demonstrate potential emission reductions on a short-term (1-hour to 24-hour) and annual basis.

Step 4 – Process the Mixture Carefully

The contaminant level analysis is the final component to the NHSM determination demonstration. In this step, a comparison must be provided that shows how the contaminant levels in the NHSM compare to contaminant levels of traditional fuels that your combustion unit is designed to burn. As of early May 2012, the contaminants that are considered should include the Clean Air Act Section 112(b) hazardous air pollutants (HAPs), the nine CAA Section 129(a)(4) contaminants, and any contaminants that could create products of incomplete combustion (PICs). Note that the December 2, 2011 revisions to the NHSM rule modify the definition of contaminants by naming 15 key contaminants and eliminating 17 contaminants that are also listed in Sections 112(b) and 129(a)(4). These December 2011 proposed revisions could apply beginning in June 2012.

The contaminant comparison should show that the NHSM contaminant levels are “comparable” to the contaminant levels in the traditional fuels that could be used in the combustion unit. Ideally, all of the NHSM contaminant levels would be less than the levels for traditional fuels. In instances where a few NHSM contaminants are greater than the levels in traditional fuels, U.S. EPA has suggested two scenarios for addressing the situation in a positive fashion. First, if the NHSM contaminant level is within a “small acceptable range” of the traditional fuel (in a U.S. EPA example the range is 5%) then the two contaminant levels are comparable. Also, the statistical means or even median values of the contaminant levels can be considered in the comparison. The second scenario involving a higher NHSM contaminant level can be addressed by discussing the process by which the contaminant becomes an adverse emission. For instance, even though one contaminant in the NHSM is present at a higher level than in the traditional fuel, the combustion process, the burner equipment, and the nature of the contaminant could effectively make the actual emissions of the contaminant inconsequential. Finally, an alternate possibility for addressing a slightly higher NHSM contaminant level could be to equate a concentration level to a mass per heat level. For example, if a NHSM contaminant level is slightly higher than the traditional fuel level but the NHSM has a higher heating value than the traditional fuel, a scenario could exist where the amount of contaminant released by the NHSM would be less than the traditional fuel simply because less NHSM is required to provide the same amount of heat input as the traditional fuel.

In our next blog we will offer some cautions regarding your NHSM determination demonstration. In the interim, there are several resources that you can contact here at ALL4 to help you with aspects of the NHSM rule or aspects of the Boiler MACT and CISWI rules, including Ron Harding or Dan Holland.

So You Operate A CISWI Unit – What’s The Good News?

Recall the March 2011 proposed Non-Hazardous Secondary Materials (NHSM), Commercial and Industrial Solid Waste Incineration (CISWI), and National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT) rules. A major concern for owners and operators of boilers that used alternate or “non-traditional” (i.e., waste) fuels at that time was how specific emissions units would be regulated under the suite of proposed rules. In accordance with the March 2011 proposed rules, a boiler would only be allowed to utilize waste fuel if the boiler was classified as an “energy recovery unit” under the proposed CISWI rule. However, such sources could opt-out of CISWI and be regulated under Boiler MACT if they ceased firing fuels classified as waste. For many owners and operators that were not yet sure whether their boiler could comply with the CISWI rule, some may have seriously considered ceasing their use of waste fuels until they were certain that their boiler could comply with the CISWI rule.

Remember also that at the time of the March 2011 proposed rules, it was unclear whether a boiler switching from firing a traditional fuel (e.g., fuel oil, coal, natural gas, etc.) to a non-traditional fuel (or waste) would be classified as a “new” or “existing” CISWI unit. The confusion related to whether a fuel switch from a traditional fuel to a waste fuel would be considered as a modification, thereby subjecting an “existing” CISWI unit to more stringent new source CISWI standards. So here’s the good news. In U.S. EPA’s December 2011 proposed reconsideration of the CISWI rule, they clarified that a traditional fuel-to-waste switch alone would not cause a boiler to be classified as a “new” unit (i.e., if the boiler doesn’t trigger new source applicability for reasons other than the fuel-to-waste switch). Although only proposed, we expect to see this interpretation maintained in the final version of the rules, which U.S. EPA intends to promulgate any day now.

Latest News On The 1-Hour SO2 NAAQS Implementation Process

On April 12, 2012, U.S. EPA’s assistant secretary Gina McCarthy recently sent letters to States outlining updates to the implementation procedures of the 1-hour sulfur dioxide (SO₂) National Ambient Air Quality Standard (NAAQS). The major news is that U.S. EPA has put a hold on the modeling requirement for individual sources for inclusion in the June 2013 Maintenance State Implementation Plan (SIP). ALL4’s Colin McCall broke the news on April 20, 2012 in his blog post “Urgent – SO2 Implementation Update”.

Now that we’ve had some time to digest the news I thought it was a good time to update everyone on the latest information. The letter sent to states from Gina McCarthy stated that stakeholder meetings would be held to address two (2) main topics:

How best to assess compliance with the SO₂ NAAQS (e.g., by defining and establishing a robust, representative monitoring network for SO₂ across the country and/or by applying the appropriate modeling approach).
How to implement the approach (e.g., implementation options and SIP timelines for areas in which violations are identified).

These stakeholder meetings have been scheduled and will be broken into the following three (3) sessions:

Session 1: Environmental and Public Health Organization Representatives – May 30, 2012, Washington, DC
Session 2: State and Tribal Representatives – May 31, 2012, Research Triangle Park, NC
Session 3: Industry Representatives – June 1, 2012, Research Triangle Park, NC

U.S. EPA has indicated that the issues that will be discussed during each of the sessions will be outlined in a white paper. In addition a summary of comments from the stakeholder meetings will also be posted on the same website following the conclusion of all three (3) meetings. ALL4 also plans on attending at least one (1) if not all three (3) of the sessions. For industry that could potentially be affected by the SO₂ NAAQS implementation, we strongly recommend attending Session 3. This is your time to provide valuable input into the process of determining how States (and facilities) will be assessing compliance with the SO₂ NAAQS.

It should be noted that the stakeholder meetings will not be addressing the level of the 1-hour SO₂ NAAQS. The 1-hour SO₂ NAAQS is a primary standard meaning that it is put in place to be protective of human health and therefore it is extremely unlikely that the 75 ppb standard will be changed. In addition it should also be noted that the letters sent to States in no way are related to modeling requirements under the Prevention of Significant Deterioration (PSD) permitting program. If modeling requirements for SO₂ are tripped for the PSD permit program, a demonstration showing compliance with the 1-hour SO₂ NAAQS is still required following procedures laid out in 40 CFR Part 51 Appendix W – “Guideline on Air Quality Models.” However, if anyone would like to comment on issues related to permit modeling, the U.S. EPA has put a second extension on the comment period for the 10^th Conference on Air Quality Modeling held in Research Triangle Park, NC on March 13-15, 2012. The extension was put into place to address the late release of “Case Studies for 1-hour NO2 and SO2 NAAQS” conducted by the AERMOD Implementation Workgroup (AIWG) which can be found here.

Based on the changes made to the 1-hour SO₂ NAAQS implementation process, ALL4 offers the following advice to our clients:

Be involved in the stakeholder meetings.
U.S. EPA’s original proposed 1-hour SO₂NAAQS implementation approach involved the installation of new ambient monitoring stations. The location of the monitoring stations in a given census statistical area was to be based on a factor equal to the product of SO₂annual emissions and population in that area. The basis of this proposed approach was to place ambient monitors in areas where the general public was most likely to be exposed to short-term peaks of SO₂concentrations. This original approach could be more favorable than specific modeling demonstrations provided that the ambient monitors are placed in areas of the general population and not located along facility fencelines. The proposal is technically justifiable but would need to be weighed versus the cost and time it would take to implement such a monitoring program.
ALL4 continues to recommend that facilities conduct exploratory modeling to assess your status with the 1-hour SO₂ NAAQS for planning purposes. The only thing that we recommend differently with the changes made to the implementation process is to conduct the modeling through legal counsel under an attorney-client privilege arrangement to keep the results confidential.
Be aware that there could still be a modeling requirement that comes out of the stakeholder meetings for the SO₂ SIP Implementation. Also, be aware that there could be a monitoring requirement that comes out of the stakeholder meetings as well.
Modeling under PSD for the SO₂ 1-hour NAAQS remains a requirement under each program, as applicable.