August 2013

Greenhouse Gas Speculation at Existing Power Plants

It’s been nearly two (2) months since President Obama released his Climate Action Plan (Plan) on June 25, 2013. In his Plan, Obama directed U.S. EPA to re-propose New Source Performance Standards (NSPS) for emissions of carbon dioxide (CO₂) for new electric generating units (EGUs) by September 20, 2013 and directed U.S. EPA to propose a CO₂ NSPS for existing EGUs by June 2014. Obama’s recent directives were in response to U.S. EPA’s failure to issue the final CO₂ NSPS for new EGUs within one (1) year of its original groundbreaking proposal on April 13, 2012. Since U.S. EPA failed to issue the final NSPS for new EGUs within one (1) year of the original proposed version, the rule must be “terminated” and U.S. EPA must propose, accept comments on, and finalize a new version of the rule. U.S. EPA recently announced its submittal of the draft re-proposed rule to the White House Office of Management and Budget, and we all wait patiently to learn whether the re-proposal will this time include unique standards for coal- vs. gas-fired plants.

Now that we have confidence that U.S. EPA is finally on track concerning the CO₂ NSPS for new EGUs, we’ve started to speculate what a future rule may look like for existing facilities. As already noted, U.S. EPA is required to propose a CO₂ NSPS for existing facilities by June 2014. Once proposed, U.S. EPA is required to finalize that rule within a year, with the understanding that the NSPS for new plants must be finalized prior to finalization of the NSPS for existing plants. Environmental gossip concerning the future CO₂ NSPS for existing facilities is on the rise, and ALL4 would like to take this early opportunity to summarize some of the possible avenues U.S. EPA may take for achieving greenhouse gas (GHG) emissions reductions through an NSPS at these existing facilities.

A unit-specific, rate-based limit (i.e., pounds per megawatt-hour limit). Proponents of this approach like that existing EGUs would not be forced to limit the amount of energy they produce, which in turn wouldn’t limit economic growth. A rate-based approach allows for production increases and the ability for facilities to remain in compliance during an economic boom. However, opponents to this approach feel that although the rate-based limit could potentially reduce short-term emissions, there is no guarantee of any long-term GHG emission reductions since such a limit would not result in emissions reductions if electricity production increases.
A hard cap. Some believe that imposing a hard cap on GHG emissions from existing facilities is the only means by which U.S. EPA can guarantee GHG emission reductions from this sector of the power industry. But if U.S. EPA takes this approach, they are destined to receive an immense amount of opposition from industry since it would not only cap emission but also cap future economic growth.
Utility upgrades. This approach is a very sensitive one that U.S. EPA will be considering very cautiously. Utility companies may need to undertake efficiency projects that would enable them to comply with the rule; however, in doing so they may extend the life of their existing EGU beyond its normal life expectancy. This scenario could result in the emissions reductions that EPA predicts to be associated with the construction of new EGUs to be negated by the extended operation of existing EGUs. U.S. EPA will be seeking a “sweet spot” where they achieve reductions from existing EGUs without forcing others to close due to an inability to comply. U.S. EPA also appreciates that many coal-fired EGUs have recently already invested a great sum of money to meet rules such as the Mercury and Air Toxics Standards (MATS). U.S. EPA will be trying to strike a balance between requiring mandatory upgrades and meeting emission limits so as not to undermine any of those historic investments or require shutdown.
Unit-specific, rate-based limits with trading programs managed by individual states. This program, similar to Option #1, will impose a rate-based GHG limit but also set a cap on overall regional emissions. By combining emission limits along with a trading program, individual states would have flexibility in managing their GHG emissions and ensuring reductions occur from existing facilities.

We’ll hopefully have a better sense of what path U.S. EPA will take concerning the future CO₂ NSPS for existing EGUs prior to U.S. EPA’s June 2014 deadline for proposal. We anticipate the spotlight on this future rulemaking to brighten following U.S. EPA’s upcoming re-proposal of the CO₂ NSPS for new EGUs this September and will keep you posted as to any additional speculations.

Hey Pennsylvania Unconventional Oil & Gas Producers: You Got a Permit for That?

The Pennsylvania Department of Environmental Protection (PADEP) has finalized updates to its list of Air Quality Permit Exemptions, specifically Categories No. 33 and 38, to add strict criteria under which natural gas dispensing facilities and oil & gas exploration, development, and production operations would be exempt from Pennsylvania air permitting requirements. This action ends a decade-plus of blanket exemptions for oil & gas production in the State. Final technical guidance document 275-2101-003 is effective August 10, 2013, and contains few technical changes to the version proposed in February 2013.

Here are the new criteria for conditional exemption from the Pennsylvania Plan Approval requirements, in brief:

Exemption No. 38 – Oil and gas exploration, development, and production facilities and associated equipment and operations

The following operations/equipment are unconditionally exempt:

Conventional wells, wellheads, and all other associated equipment.
- Conventional wells are now defined as any well that does not meet the definition of unconventional gas well in 58 Pa. C.S §3203.
Well drilling, completion and work-over activities.
Non-road engines as defined in 40 CFR §89.2.

Unconventional wells, wellheads, and associated equipment are conditionally exempt if the following criteria are met:

Within 60 days of the well beginning production, and annually, owner/operator must perform a leak detection and repair (LDAR) program according to PADEP requirements. Leaks are to be repaired no later than 15 days after leak detections, unless facility shutdowns or ordering of replacement parts are necessary for repair of the leaks.
- Leak detection and repair for storage vessels are to be performed in accordance with 40 CFR Part 60, Subpart OOOO.
- Five (5) criteria are provided in the exemption for use in determining when a leak is considered repaired.
- Recordkeeping requirements apply to leak repair methods and delays.
Storage vessels/tanks or other equipment equipped with VOC emission controls must achieve emissions reduction of 95% or greater, and demonstrate compliance consistent with 40 CFR Part 60, Subpart OOOO or an alternative and Department approved test method.
Combined VOC from all sources at a facility < 2.7 TPY on a 12-month rolling basis.
- If the VOCs include HAPs, additional HAP exemption criteria apply.
  - Combined HAP emissions at a facility < 1,000 lbs of a single HAP or one (1) ton of a combination of HAPs in any consecutive 12-month period.
- Emissions already permitted by PADEP (e.g., plan approval, general permit, exempted operations under No. 38, etc.) do not count towards this total.
Flaring is only to be conducted under certain restricted conditions:
- Flaring used at exploration wells to determine the existence of gas or for appraisal.
- Flaring used for repair, maintenance, emergency or safety purposes.
- Flaring used for other operations at a wellhead or facility to comply with 40 CFR Part 60, Subpart OOOO.
- Permanent enclosed flares designed and operated in accordance with the requirements of 40 CFR §60.18.
Combined NO_x emissions from all stationary ICE at a facility < 100 lb/hr, 1,000 lb/day, 2.75 ton/ozone season, and 6.6 TPY on a 12-month rolling basis.
- Emissions already permitted by PADEP do not count towards this total.

Exemption No. 33 – Compressed natural gas dispensing facilities

Combined NO_x emissions from all stationary internal combustion engines (ICE) at a facility < 100 lb/hr, 1,000 lb/day, 2.75 ton/ozone season (May-September), and 6.6 tons per year (TPY) on a 12-month rolling basis.

Emissions already permitted by PADEP do not count towards this total.

Combined VOC emissions from all sources at a facility < 2.7 TPY on a 12-month rolling basis.

If the VOCs include HAPs, additional HAP exemption criteria apply.
- Combined HAP emissions at a facility < 1,000 lbs of a single HAP or one (1) ton of a combination of HAPs in any consecutive 12-month period.
Emissions already permitted by PADEP do not count towards this total.

Owner/operator must annually perform a leak detection and repair (LDAR) program according to PADEP requirements. Leaks are to be repaired no later than 15 days after leak detections, unless facility shutdowns or ordering of replacement parts are necessary for repair of the leaks.

Leak detection and repair for storage vessels are to be performed in accordance with 40 CFR Part 60, Subpart OOOO.
Five (5) methods are provided in the exemption for use in determining when a leak is considered repaired.
Recordkeeping requirements apply to leak repair methods and delays

Owners/operators must otherwise comply with all the requirements of the newly-revised NSPS Subpart OOOO that apply to them. Please note that storage vessels exempt from the requirements of Subpart OOOO may not necessarily be exempt from the Pennsylvania Plan Approval process.

Compressed natural gas dispensing facilities, unconventional wells, wellheads, and associated equipment constructed, reconstructed, or modified prior to the effective date of the revised exemption list (August 10, 2013) may continue to operate under the blanket Plan Approval Exemption that was originally relied upon, provided they continue to operate unchanged in physical setup and method of operation. Any sources constructed, reconstructed, or modified after August 10, 2013 will either need to abide by the revised exemption criteria, request exemption via a request for determination (RFD), apply for a general permit (as applicable), or apply for and receive a Plan Approval from the State. Note also that, if there are other operations at a facility that would require a permit, those plan approval exempted emission units may be required to be included in the facility’s operating permit.

If you have been assuming that your planned oil and gas exploration, development, and production facility or modification does not need a Plan Approval, we highly recommend doing a careful review to make sure you will meet the criteria for exemption, and possibly submitting a Request for Determination (RFD) to PADEP to verify that you are in the clear. If not, you may need to get the permit application process started. Contact ALL4 at any time if you have further questions about what rules your oil & gas facility may be subject to.

All4 Inc.: Coming Soon to a Campus Near You

There is something in the air this time of year that gets the energy pumping. The leaves are changing, the lazy days of summer are slowly coming to a close, and the anticipation of a new school year has most college students humming with excitement to get back to campus to start the semester. For All4 Inc. (ALL4), the change from summer to autumn is a busy time of year on the recruitment front. For underclassmen, back to school means an opportunity to meet new friends, go shopping for new school supplies, and attending ice cream socials for a bunch of organizations on campus. For seniors, it means all of these same things; but there is also the added excitement and anticipation of going to the career fairs and searching for a company that can provide you with a job that aligns with your career interests.

If you are interested in working in the environmental business, you might want to make it a point to come and stop by ALL4’s booth at a career fair near you. ALL4 is an environmental consulting company that specializes in air quality consulting services – primarily assisting our clients with complex air permitting, air quality modeling, continuous monitoring, and regulatory compliance issues. ALL4 was founded in 2002 and is headquartered in Kimberton, PA (about 15 minutes west of Valley Forge National Park). ALL4 also operates a Southeast Regional Office located in Kennesaw, GA (½ hour northwest of Atlanta.) ALL4 employs a mix of professionals with diverse educational backgrounds ranging from meteorology, environmental science, and mechanical, civil, and chemical engineering.

If you are an underclassman, you can still stop by and talk to us; we won’t bite. We might not have any openings for internships at this time, but you can talk to us and figure out if our business strikes enough interest in you to cause you to pursue a job at ALL4 when you are a senior.

The start of a new academic year comes with a packed itinerary of career fairs. Check out the list below to see which university career fairs that ALL4 will be making an appearance at. Also, check out our webpage for college students for further information and videos.

September 9, 2013 – Georgia Tech Career Fair
September 11, 2013 – Villanova Career Fair
September 19, 2013 – Penn State University Fall Career Fair
September 26, 2013 – Delaware University Fall Career Fair
October 3, 2013 – Drexel University Fall Career Fair

Deja Vu All Over Again? U.S. EPA Announces Boiler MACT Limited Reconsideration

At ALL4, most of our clients are impacted by at least one (1) of the Boiler MACT rules. While a good portion of these clients have begun developing their compliance strategies for these rules with looming compliance dates that will be here before we know it, there have been a small percentage of clients that have delayed their compliance planning because of what some might say is the boy who cried wolf syndrome. Boiler MACT regulations have existed for several years in various forms and these clients have been burned in the past by installing air pollution control devices and undergoing extensive permitting projects to comply with Boiler MACT and its various incarnations. Now, quite understandably, they have been hesitant to prepare for the latest versions of these rules because they are expecting that litigation will once again result in the delaying or overturning of the rules.

On August 6, 2013, the U.S. Environmental Protection Agency (U.S. EPA) announced that it will begin a limited (for now) reconsideration of certain monitoring requirements, emission limits, and other provisions in the two (2) Boiler MACT rules and the Commercial and Industrial Solids Waste Incinerators (CISWI) rule that we have all become so familiar with in 2013. So, is what happened on August 6, 2013 really the beginning of wholesale changes or just a small blip in the journey? Time will tell, and while I don’t think the rules will go away entirely, it is prudent to maintain awareness of the actions taken by U.S. EPA as they are announced since they could impact evolving compliance strategies. So without further ado, the following summarizes the proposed elements for reconsideration under Major and Area Source Boiler MACT and the CISWI Rule.

For Major Source Boiler MACT, U.S. EPA will reconsider how startup and shutdown periods are defined, as well as the requirements associated during such periods; a revised emission limit for carbon monoxide based on a minimum level of 130 parts per million; and the role of continuous parametric monitoring systems in the rule.

For Area Source Boiler MACT, U.S. EPA similarly will reconsider the startup and shutdown definitions; alternative particulate matter (PM) standards for new oil-fired boilers that burn low-sulfur fuel; the potential to establish a subcategory for “limited-use boilers;” potentially eliminating PM performance testing for units that emit PM at less than half the applicable limit; and the possibility to eliminate fuel sampling for coal-fired boilers based on an initial compliance demonstration.

Finally, for CISWI, U.S. EPA will reconsider the definition of continuous emissions monitoring systems (CEMS) data during startup and shutdown periods, and the PM limit for the waste-burning kiln subcategory.

While none of these reconsiderations would be considered major revisions to the rule, the reconsideration process itself is the newsmaker here. After a proposed format and schedule for briefing are submitted in late September 2013, an update to the reconsideration process should become available so be sure to check back with us frequently for updates.

Final Amendments to 40 CFR Part 60 Subpart OOOO

On August 2, 2013, the U.S. Environmental Protection Agency (U.S. EPA) finalized revisions to the storage vessel provisions of 40 CFR Part 60 Subpart OOOO – Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. The revisions will impact owners and operators of storage vessels used in the oil and natural gas production and transmission industry. The rule finalizes certain aspects of the proposed rule, and makes several important changes to requirements (e.g., notifications, emissions, definitions, and reporting). To be a bit more specific, the updates extend and phase the emission control deadline for affected storages vessels and provide an alternative emission limit, to name a few.

You may be asking yourself…so how does this apply to me and what do I do next? Please read below to find out as I address several key aspects regarding applicability, compliance requirements, and dates.

What Storage Vessels Are Affected?

Let’s first take a look at what storage tanks are considered “affected facilities” since the updated rule revised a few key definitions relating to “storage vessel affected facility”. A storage tank is considered an affected facility if all of the following conditions apply:

It was constructed, reconstructed, or modified after August 23, 2011,
It has potential to emit (PTE) volatile organic compounds (VOC) of six (6) or more tons per year,
It is used to store any of the following
- crude oil,
- condensate – updated definition: “means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at standard conditions”
- unrefined petroleum liquids (a.k.a., intermediate hydrocarbon liquids), or
- produced water – updated definition: “means water that is extracted from the earth from an oil or natural gas production well, or that is separated from crude oil, condensate, or natural gas after extraction”
- It is located anywhere along the oil and natural gas production and transmission process, specifically:
  - Natural Gas – from well to the point where gas enters the distribution system
  - Oil – from well to the point where oil is transferred to the pipeline for crude oil transmission

A storage vessel is NOT considered an affected facility and is not covered by this standard if any of the following conditions apply:

It is a fuel tank,
It has an enforceable permit limit that is less than six (6) tons per year and is under federal, state, local or tribal authority, or
It is located at a refinery

Are VOC Emission Control and Reductions Required?

Yes, the updated rule still requires VOC emissions to be reduced by 95 percent for all affected storage vessels. However the updated rule establishes an extended and phased deadline for complying with this requirement.

When are VOC Emission Control and Reductions Required?

The April 2012 version of the rule required VOC emission reduction for all affected storage tanks by October 15, 2013. However the revised rule specifies two compliance dates (i.e., for Group 1 and Group 2 vessels) that are based upon the vessel(s) construction or modification date. The revised rule considers the fact that VOC emissions from storage tanks generally decline over time as production from wells and associated liquids decline. I know what you are thinking…what are Group 1 and Group 2 storage tanks? Read on to find out.

The revised rule definition of Group 1 and 2 storage vessels are as follows:

Group 1 vessel: means a storage vessel for which construction, modification or reconstruction has commenced after August 23, 2011, and on or before April 12, 2013
Group 2 vessel: means a storage vessel for which construction, modification or reconstruction has commenced after April 12, 2013

If your storage vessel is affected or even if you are not yet sure, please mark your calendar with the deadlines for the phased-in controls and notification requirements bulleted below for each group of affected storage tanks.

Group 1 vessels:
- Submit the notification identifying each affected Group 1 storage tank with the initial annual report that is due no later than 90 days after the end of the initial compliance period (i.e., January 13, 2014)
- Achieve the required emissions reduction by April 15, 2015
Group 2 vessels:
- Achieve required emissions reduction by April 15, 2014, or within 60 days after startup, whichever is later

You may have just noticed two key changes that occurred between the April, proposed, and final versions of the rules. If you missed them, here they are:

All affected storage tanks (i.e., Group 1 and 2) must control and reduce VOC emission by 95 percent. Yes, this means that the U.S EPA is NOT finalizing the proposed requirement for Group 1 tanks to control VOC emission only if there is a change that potentially would increase the vessel’s VOC emissions.
Owners/operators now have 90-days to submit annual reports (not the 30-days originally specified)

Does the Final Rule Still Include Any Alternatives to Reducing VOC Emissions by 95 Percent?

If you are cringing at the thought of having to install controls, you should be happy to learn that there is still an alternative compliance option within the final rule. The final rule provides an alternate sustained uncontrolled actual VOC emission limit of less than four (4) tons per year. Before you celebrate, the rule requires owners/operators to demonstrate compliance using the 12 months immediately preceding the demonstration and to re-evaluate emissions on a monthly basis. Also, if an affected storage vessel’s VOC PTE decreases to less than 6 tons per year, the storage vessel will remain an affected facility.

When Do I Need To Estimate My Storage Tank(s) Potential Emissions?

You may want to revisit the definition of Group 1 and 2 storage vessels again to ensure that the deadlines are understood. Tanks owners/operators within the oil and gas industry must estimate all of their tank(s) potential emissions by the dates bulleted below to determine if they are subject to this NSPS (i.e., affected facilities).

Group 1 vessels: By October 15, 2013
Group 2 vessels: Within 30-days of startup

If you have not done so already, be sure to mark your calendar as appropriate.

This entry is getting quite long and could be much longer as I did not cover other updates such as specific details regarding calculating VOCs, test protocol requirements, and compliance monitoring, to name a few. U.S. EPA has published a fact sheet that summarizes the information above as well as action and updates not covered. The official version of the rule is forthcoming in the Federal Register. A pre-publication version can be viewed here.

If you still have unanswered questions or would like to learn how ALL4 can provide your organization with compliance assistance related to this and other air rules, feel free to contact me at jkleinle@all4inc.com.

Clearer Water? – EPA Proposes Electronic Reporting and Transparency for NPDES Facility Information

On July 30, 2013, U.S. EPA continued its move toward more transparency of environmental information by proposing the National Pollutant Discharge Elimination System (NPDES) Electronic Reporting Rule. The proposed rule would modify 40 CFR Parts 122 (EPA Administered Permit Programs: the National Pollutant Discharge Elimination System), 123 (State Program Requirements), 403 (General Pretreatment Regulations for Existing and New Sources of Pollution), 501 (State Sludge Management Program Regulations), and 503 (Standards for the Use or Disposal of Sewage Sludge) and would create 40 CFR Part 127 (NPDES Electronic Reporting Rule). The proposed rule would require electronic reporting for NPDES reports that are currently paper-based. By switching to an electronic-based system as opposed to a paper-based system, U.S. EPA expects benefits by bringing about a shift in regulatory resources from data management activities to activities more in line with solving water quality and noncompliance issues.

As proposed, the NPDES Reporting Rule would not increase the amount of information required from NPDES regulated facilities under the current regulations. The proposed NPDES Electronic Reporting Rule would require that current NPDES program written reports, including Discharge Monitoring Reports (DMRs), Notices of Intent, general permit waivers, certifications, and notices of termination of coverage, be submitted directly to U.S. EPA electronically through the National Environmental Information Exchange Network. Authorized NPDES permitting authorities (e.g., States, Tribes and Territories) would also continue to receive this information, and could have the opportunity to be designated to receive the information first and pass it along to U.S. EPA. Additionally, NPDES permitting authorities would also be required to report to U.S. EPA information they currently maintain on NPDES program facilities, including the following information:

NPDES permit applications
Permit information (outfalls, limits, etc.)
Compliance determination information
Inspections
Enforcement response information

So why does U.S. EPA now want all of this information electronically? In the proposal, U.S. EPA states its intent to make all this data available to the public to promote transparency and accountability. U.S. EPA says it would also use the data to compare performance across authorized programs. Other benefits that U.S. EPA identifies include relief for permitting authorities from processing paper reports and annual reporting to U.S. EPA, and reduced reporting burdens on permitted facilities from the efficiencies of electronic reporting.

The proposed implementation schedule for the NPDES Reporting Rule would be a phased approach following final promulgation of the rule with milestones including:

U.S. EPA sponsored webinars, training, and technical assistance to States and other NPDES permitting authorities upon final rule publication.
States and other NPDES permitting authorities would work with U.S. EPA to designate who will receive the electronic NPDES information from facilities (initial recipients) and publish those designations.
States and other NPDES permitting authorities would implement the Federal electronic reporting rule one (1) year after the promulgation date.
States and other NPDES permitting authorities not identified in Phase I in the initial group of recipients would report their NPDES information electronically two (2) years after the effective date of the rule.

U.S. EPA will accept comments on the current proposal through October 28, 2013. The proposed NPDES Reporting Rule has a large scope and would have broad applicability. For that reason, U.S. EPA has already committed to publishing a supplemental notice 180 days after the closure of the public comment period if comments are received that prompt significant changes to the proposed rule. This is a clear sign that a proposed rule such as this can take quite a while to be finalized. But however long it takes, the end result for NPDES permitted facilities will be more opportunity for engagement with the public and regulatory agencies regarding environmental performance.

Five Considerations of Being a CISWI Unit

With so much talk of boilers and heaters since the 4 Rules were published in early 2013, most facilities are focused on developing an understanding and strategy to comply with the Maximum Achievable Control Technology (MACT) standards for Boilers (commonly referred to as Boiler MACT). However, one of the 4 Rules is the Commercial and Industrial Solid Waste Incineration (CISWI) rule, and facilities may want to consider this rule as a compliance alternative to Boiler MACT. The CISWI rules are codified at 40 CFR Part 60, Subpart CCCC for new, modified, or reconstructed units (i.e., New Source Performance Standards) and Subpart DDDD for existing units (i.e., Emission Guidelines). This concept of choosing to be regulated under the CISWI regulations may not be as far-fetched as one might think. In fact, from an emission limit, fuel flexibility, and timing perspective, a case can be made that some boilers could be better off regulated under CISWI rather than Boiler MACT. Let’s look at the following five (5) considerations when deciding whether to go down the CISWI path or the Boiler MACT path:

Fuel flexibility
Compliance schedule
Compliance requirements
Emission limits
Public perception

Before we dive into the specific considerations of being a CISWI unit as opposed to a Boiler MACT unit, let’s review the basics of CISWI. A CISWI unit is any distinct operating unit of any commercial or industrial facility that combusts, or has combusted in the preceding six (6) months, any solid waste. The CISWI rule applies to 106 existing units (according to U.S. EPA estimates) in four (4) subcategories: incinerators, energy recovery units (ERUs), waste-burning kilns, and small, remote incinerators. ERUs are further broken down into three (3) subcategories: ERU liquids and gases, ERU biomass, and ERU coal. Waste-burning kilns have two (2) subcategories, which are differentiated based on carbon monoxide (CO) emission limits: long kilns and preheater/precalciner categories.

Since the combustion of solid waste is what distinguishes a CISWI emissions unit from a Boiler MACT emissions unit, it is important to understand the definition of solid waste. For rule applicability, 40 CFR Part 258.2 defines the term solid waste. Solid waste is defined as any garbage, or refuse, sludge from a wastewater treatment plant, water supply treatment plant, or air pollution control facility and other discarded material, including solid, liquid, semi-solid, or contained gaseous material resulting from industrial, commercial, mining, and agricultural operations, and from community activities. Solid waste is not a non-hazardous secondary material (NHSM) that meets the “legitimacy criteria” as outlined at 40 CFR Part 241.3(b).

The CISWI rule has many components including increments of progress and control plans, preconstruction siting analysis (for new sources), waste management plans, operator training and qualification, air pollution control inspections, emission and operating limits, performance testing, initial and continuous compliance requirements, and monitoring, recordkeeping, and reporting requirements. It is noteworthy that there are no major and area source distinctions in the CISWI rule. Since the effective date of the CISWI rule for existing sources (February 2013), most facility operators have been exposed to some type of webinar, conference, or other training that provided the basic requirements of CISWI and Boiler MACT rules. In lieu of going through the details of each component of two rules, let’s look at those components that should be evaluated as part of the CISWI/Boiler MACT comparison.

1. Fuel Flexibility

Fuel flexibility is probably the most important consideration when comparing CISWI to Boiler MACT. Boiler MACT fuel categories are clearly defined, and any fuel outside of those categories must be proven to be a non-waste NHSM following the legitimacy criteria contained at 40 CFR Part 241.3(d). Under the CISWI rule, facilities can combust traditional fuels along with solid wastes. For example, a facility that combusts biomass along with a pre-consumer NHSM (e.g., off-spec plastic parts) may want to evaluate becoming a CISWI unit in lieu of being a Boiler MACT unit. Under the current Boiler MACT rules, the example facility would need to cease firing that valuable and cheap alternate fuel in order to be classified as a Boiler MACT unit, since off-spec plastic parts are considered a solid waste pending a viable non-waste determination. However, the unit could continue to fire any NHSMs under the CISWI rule.

2. Compliance Schedule

Another benefit of falling under the CISWI category is the potentially extended compliance schedule. Existing CISWI units have to comply with the standards no later than three (3) years after U.S. EPA approves a State Plan or five (5) years after the February 7, 2013 publication date (i.e., February 7, 2018), whichever is earlier. It is highly likely that the compliance date will ultimately be five (5) years after the CISWI rule publication date, thus, the February 7, 2018 compliance date. The Boiler MACT units are facing a March 21, 2014 compliance date for area sources and a January 31, 2016 compliance date for major sources, and thus the CISWI compliance date gives existing facilities between two (2) and four (4) more years to implement a compliance strategy. These Boiler MACT dates are fast approaching. The CISWI compliance date allows facilities a little more breathing room to determine compliance strategy and implementation time. The Boiler MACT sources, especially area sources, are on a compressed timeline to get their compliance strategy implemented, especially once air permitting activities are taken into account.

3. Compliance Requirements

Both rules have compliance requirements (and plenty of them). The common requirements include performance testing, emission and operating limits, monitoring, recordkeeping, and reporting. Let’s focus on the requirements that are different:

Increments of Progress
Waste Management Plan
Operator Training and Qualification

State Plans (i.e., state rules developed to implement the Subpart DDDD Emission Guidelines) must include at least two (2) increments of progress for regulated CISWI units. Increments of progress requirements become applicable if you plan to achieve compliance more than one (1) year following the effective date of the State Plan. If this path is chosen, facilities must submit a final control plan and achieve final compliance by a specific date in the State Plan. The final control plan must include the measures that will be taken, including a description of any process changes or air pollution control device changes, to comply with the CISWI emission limits. A facility must notify, no later than 10 days after the increment compliance date, that they have achieved the increment of progress. A facility must complete all of the process changes and retrofit of control devices, if needed, that are specified in their final control plan to achieve the final compliance increment of progress.

Another different compliance component to the CISWI rule is the requirement to write and maintain a Waste Management Plan (WMP). This is a plan that identifies the feasibility and methods used to reduce or separate certain toxic components of a solid waste in order to reduce or eliminate their emissions due to being incinerated. The WMP would rank the practical and feasible contaminant reduction options by effectiveness, costs of separation measures, emissions reductions expected, and any other environmental or energy impacts for each option. The facility would only implement those measures that are considered practical and feasible. The WMP must be submitted to U.S. EPA or the delegated enforcement authority no later than the date required to submit the final control plan discussed above.

Yet another requirement that is different from the Boiler MACT rules is operator training and qualification. A CISWI unit can only be operated when a fully trained and qualified CISWI unit operator is accessible. What does this mean? It means that a trained and qualified operator is either on-site at the time of operation or can be at the facility within one (1) hour. The operator can be someone who operates the CISWI unit directly or supervises plant personnel who operate the unit. The training must include the following elements: environmental concerns (including types of emissions), basic combustion principles (including products of combustion), operation of the facility’s specific type of incinerator (including proper startup, waste charging, and shutdown procedures), combustion controls and monitoring, operation of air pollution control equipment, inspection and maintenance of the incinerator and air pollution control device(s), corrective actions to prevent and correct malfunctions, ash characteristics and handling procedures, all applicable workplace standards, pollution prevention, and waste management practices. The training program must include an exam and written material that can be referenced after the course is over. An operator needs to maintain his qualification by completing an annual review or refresher course.

3. Compliance Requirements

Increments of Progress
Waste Management Plan
Operator Training and Qualification

4. Emission Limits

Let’s look at a biomass fuel and coal example and compare the Boiler MACT and CISWI emission limits. Note that the emission limits presented in the CISWI rule are corrected to seven (7) percent oxygen whereas the Boiler MACT emission limits are presented as corrected to three (3) percent oxygen. For comparison purposes, we have presented all emission limits as corrected to three (3) percent oxygen.

By U.S. EPA’s estimate, the major source Boiler MACT will regulate 14,000 boilers and process heaters that burn solid, liquid, and gaseous fuels. U.S. EPA designated nine (9) different boiler designs to be regulated. Similarly, the CISWI rules regulate several different combustion units all of which combust a solid waste; however, emission limits for “energy recovery units” are the most appropriate to compare with Boiler MACT emission limits, as these units “would be considered boilers and process heaters if they did not combust solid waste.” Shown below is a table that provides a side-by-side comparison of the emission limits that would apply under Boiler MACT for existing coal and biomass boilers (stoker and stoker with sloped grate, respectively) and under CISWI for existing energy recovery units. For reference purposes, the New Source Performance Standards (NSPS) Subpart Db oxides of nitrogen (NOX) and sulfur dioxide (SO2) coal emission limits are included in the table.

Note: All values are at 3% O2.
(a) NSPS Subpart Db values are italicized and provided for reference purposes, as there are no Boiler MACT limits for SO2 and NOX.

As shown in the table, the comparison tells a different story for biomass and coal units. For biomass units, the CISWI biomass emission limits are more restrictive than the Boiler MACT emission limits for carbon monoxide (CO), filterable particulate matter (PM), mercury (Hg), and hydrochloric acid (HCl). In addition, the CISWI biomass SO2 emission limit could represent an issue for boilers that co-fire limited amounts of high sulfur fuels (e.g., coal or high sulfur oil). For coal fired units, the CISWI emission limits are higher for PM and Hg and are lower for CO and HCl relative to the Boiler MACT emission limits. For SO2 and NOX, the CISWI emission limits are higher than those for the NSPS Subpart Db.

A facility should consider the degree of fuel flexibility desired with the amount of effort required to meet emission limits. Facilities would need to do some preliminary evaluations when considering the CISWI path to ensure their fuels fired meet the CISWI emission limits. Similarly, if a facility is contemplating going down the Boiler MACT path, preliminary engineering testing needs to be completed to determine how the facility fares against the Boiler MACT emission limits.

5. Public Perception

Public perception of units firing solid wastes versus traditional fuels can also play a role in a facility’s decision regarding CISWI and Boiler MACT. Firing solid wastes tends to have a negative connation even if a facility may be subject to more stringent emission limits than a non-waste combusting source. If a facility does decide to comply with the CISWI rule, the public perception can be influenced through education and outreach to the community surrounding the facility. The public perception will depend on each facility’s location and community situation. A facility should definitely keep public relations in mind when deciding which path to choose. It could be a deciding factor. Depending on one’s community, there could be a lot of opposition to being a CISWI unit.

When choosing a compliance strategy for your boiler, heater, or incineration unit, take into account the considerations described herein. Weigh the pros and cons of each for your particular facility, community, and situation. There is no clear cut answer. It is facility-specific. The operations of one facility may lend itself to becoming a CISWI unit while another may not. How could you realize a business and compliance advantage by operating under the CISWI rule? What would an environmental compliance advantage mean for you and your business? If you think that the CISWI rule might be an alternative to Boiler MACT for you or you want to learn more, contact us to discuss your specific concerns.