A Meteorologist’s Look at the Polar Vortex and Boiler MACT
As a Certified Consulting Meteorologist (CCM), I am actively engaged with colleagues in the American Meteorological Society (AMS) regarding the interaction of weather and climate on industry. At this year’s AMS annual meeting in Atlanta, I co-chaired the CCM Forum, which was focused on consulting opportunities for CCMs related to hazard planning. Hazard planning, in a general sense, consists of three phases: prior to an event, during an event, and after an event. An event, from a meteorologist’s perspective for this forum, usually is related to a situation such as a severe thunderstorm, flash flood, blizzard, or hurricane. For this particular session, which happened to fall just one week after a winter storm literally shut down the Atlanta area, much of the chatter (both technical and good-natured fun) was focused on this year’s buzz word, “polar vortex.” Following our discussions, I began to think about how weather (particularly long duration cold snaps) can impact facilities regulated by Boiler MACT, which most of the regulated community would agree is a hazard on multiple levels! Along with the usual environmental compliance challenges of Boiler MACT is the matter of dealing with operational challenges, in particular, natural gas supply curtailments.
So how does weather (and forecasting the weather, or in the spirit of the recent CCM forum, “pre-planning” for an event such as a natural gas curtailment) impact your Boiler MACT compliance? It will hit home most likely for facilities with dual fuel boilers (those that primarily fire natural gas, but have retained the ability to burn fuel oil as a backup fuel). Natural gas boilers will typically be considered gas 1 units under both the area source and major source Boiler MACT rules. Within the definition of a gas 1 boiler is an allowance to fire fuel oil for up to 48 hours per year while maintaining the advantageous gas 1 boiler classification (i.e., gas 1 units are not subject to numerical emission limits). Those 48 hours are limited to non-curtailment periods only, whereas fuel oil usage is unlimited under a curtailment scenario.
The nuance of what is considered curtailment is contained within its definition in the rule, which states that “a period of gas curtailment or supply interruption means a period of time during which the supply of gaseous fuel to an affected boiler is restricted or halted for reasons beyond the control of the facility.” The definition goes on to state that “the act of entering into a contractual agreement with a supplier of natural gas established for curtailment purposes does not constitute a reason that is under the control of the facility.” In other words, having a contractual agreement with curtailment provisions is typically considered a reason that is beyond the control of the facility – the hours of oil usage during a gas curtailment would not count against the 48 hours per year threshold.
However, the definition further states that “an increase in the cost or unit price of natural gas due to normal market fluctuations not during periods of supplier delivery restriction does not constitute a period of natural gas curtailment or supply interruption.” Furthermore, “on-site gaseous fuel system emergencies or equipment failures qualify as periods of supply interruption when the emergency or failure is beyond the control of the facility.” Therefore, switching to fuel oil solely because the price of gas exceeds the price of oil is not a reason that is beyond the control of the facility – the hours of oil usage under this scenario would count against the 48 hours per year threshold.
Prior to the winter of 2013-14, many facilities that we consulted with regarding Boiler MACT had not experienced more than a handful of gas curtailments over the past several years. This winter alone has resulted in the same number of curtailment orders as during the past several years. While one season of harsh winter weather does not a trend make, facilities are encouraged to revisit their natural gas and fuel oil firing plans for the near future. If a facility does not have a contractual arrangement with its gas supplier, an extended curtailment order could result in burning enough fuel oil to move your boiler into a less desirable liquid fuel subcategory.
How has the winter of 2013-14 impacted your facility’s operations? Did you experience a gas curtailment period? What changes are you evaluating at your facility to minimize impacts of extreme weather in the future? As we all wait patiently (or not) for winter to come to an end, I’d like to think that we are in phase three of hazard planning…for now.
Related content:
U.S. Court of Appeals Litigation Schedule Could Derail Boiler MACT Compliance
The ongoing litigation around the Major Source Boiler MACT could potentially put facilities trying to comply with the rule in a very difficult position. The U.S. Court of Appeals for the District of Columbia (Court) announced the court schedule for litigation on January 31, 2014. For the Major Source Boiler MACT litigation, the Court has ordered industry and environmentalists to file opening briefs on March 28, 2014. Final briefs from all plaintiffs and U.S. EPA are due September 9, 2014, which is later than previously requested by interested parties. After the completion of opening and final briefs, the court will hold oral arguments and issue a final judgment. This process can take more than a year. In addition to the Major Source Boiler MACT, the Court also issued the litigation schedule for the Area Source Boiler MACT, Commercial and Industrial Solid Waste Incinerator (CISWI) Rule, and the Non-Hazardous Secondary Materials (NHSM) Rule.
With a decision not expected potentially until mid-2015, facilities that may have chosen to wait until the legal issues were sorted out to implement a compliance strategy will have very little time to comply with the Major Source Boiler MACT requirements by the current compliance date of January 31, 2016. On the other hand, facilities that are already taking the necessary steps to comply with the Boiler MACT requirements, such as investing millions of dollars to update existing or install new control devices, replacing aging boilers, and converting boilers to natural gas or other “lower polluting” fuels, may find themselves frustrated with the judgment come 2015. If the Court rules that the rule was not stringent enough or even that the rule was too stringent, facilities will have invested millions of dollars to comply with a rule and emission limits that will no longer be the measure of compliance.
All of this compounds with the fact that U.S. EPA is currently reconsidering the Boiler MACT and CISWI rules. The reconsideration is related to how the emission limits were established. U.S. EPA expects the reconsideration to be completed by September 2015 at the latest.
All in all, the ongoing Boiler MACT litigation puts facilities that are trying to comply with this rule in a very difficult position. It adds to the uncertainty around the rule and prolongs the waiting game for a final decision. Keep checking ALL4’s blog for the latest news on the Boiler MACT legal proceedings.
Related Articles –
PADEP AIMS Alert
If your company annually reports its air emissions to the Pennsylvania Department of Environmental Protection (PADEP) for inclusion in its Air Information Management System (AIMS), you will notice an additional pollutant in the forms for 2013: the condensable portion of particulate matter (listed on the AIMS forms as PM-CON). Based on the revised AIMs forms, it now appears that PM-CON should be reported as a separate speciated pollutant in conjunction with both PM2.5 and PM10. ALL4 contacted PADEP for clarification regarding the intent of this additional reportable pollutant. Based on the verbal response from PADEP, their intent is to split the reporting of particulate matter into PM2.5 (filterable), PM10 (filterable), and PM condensable (which includes both the condensable portion of PM2.5 and PM10 as the condensable portion is particulate less than 2.5 micron in size). PADEP is still finalizing revised AIMS Instructions that are not yet available. This change goes along with PADEP’s desire to gather more accurate information on the different forms of fine particulate matter that are emitted which started with the electric utility facilities a couple years ago. This will require reworking your regularly reported PM2.5 and PM10 emissions into filterable and condensable portions, even if you have already reported condensable PM emissions.
With only a few weeks left until the March 1, 2014 deadline, this change could represent a significant effort for facilities that operate many sources that emit particulate matter. Emission factors for condensable particulate matter may or may not be available for all types of sources, and emission testing data is likely even harder to come by. We’ll update this blog post as more information becomes available. In the meantime, start looking at your calculations and allowing for some additional time to complete your report.
Related content:
Portland Cement Manufacturers: Do You Know When to Submit Your O&M Plan to Comply With the February 2013 Amendments to 40 CFR Part 63, Subpart LLL?
Back in February 2013, the U.S. Environmental Protection Agency (U.S. EPA) amended 40 CFR Part 63, Subpart LLL – National Emission Standards for Hazardous Air Pollutants From the Portland Cement Manufacturing Industry (Subpart LLL). We are fast approaching the February 12, 2014 compliance date for operations and maintenance (O&M) plan requirements for existing sources with requirements for open clinker storage piles.
Pursuant to 40 CFR §63.1347(a), an owner or operator subject to the requirements for open clinker storage piles must prepare a written O&M plan to address the requirements. Also, the plan must be submitted to the Administrator for review and approval as part of the application for a part 70 permit.
During recent communications with affected facilities and regulators, I have learned of frequently asked questions (FAQs) regarding the submittal of written O&M plans. This blog responds to two (2) FAQs and is based upon clarification provided through the Office of Enforcement and Compliance Assurance (OECA) of the U.S. Environmental Protection Agency (U.S. EPA) and the Pennsylvania Department of Environmental Protection (PADEP), Division of Permits. The questions and responses are provided below:
Question No. 1: Does the written O&M plan need to be submitted on or before the February 12, 2014 compliance date?
Response: The written O&M plan does not need to be submitted to the Administrator on or before the February 12, 2014 compliance date for existing sources with requirements for open clinker storage piles.
The fugitive dust emissions control measures that are appropriate for the site conditions must be included in your O&M plan and the actual measures must be in practice by February 12, 2014. Furthermore, the O&M plan covering these new clinker pile requirements should be made available to the Administrator, if requested.
Disclaimer: A state can require your O&M plan to be submitted separately on or before the February 12, 2014 compliance date if they so desire. If you are not in the state of Pennsylvania, it would be wise to obtain confirmation from your State that they are not requiring submittals as a “Part 70 Application”, as the application and check request could take time to prepare.
Question No. 2: What type of “application” should be submitted to include an O&M plan (e.g., renewal, administrative amendment, minor modification, or significant modification)?
Response: A written O&M plan should be submitted to the Administrator for review and approval as part of any subsequent application for a Part 70 permit that is submitted after February 12, 2014. Please note that your subsequent application for a Part 70 permit may be here sooner than you realize. According to 40 CFR 70.7(f), there are several circumstances when a permit must be reopened. For example, a permit shall be reopened within 18 months of new standards being promulgated that apply to the sources, if there are three or more years left in the permit term (40 CFR 70.7(f)(1)(i)). The permitting authorities will then incorporate these newly promulgated standards into the Title V permit. The bottom line is that if your permit term has three or more years left, you may need to reopen the permit no later than August 12, 2014.
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 quality rules and regulations, please contact me at (610) 933-5246 x120 or at jkleinle@all4inc.com.
Kimberton Office Phone System Down
The Kimberton Office phone system is temporarily down after a part failure. The replacement part has been ordered for deilvery tomorrow, and the phone system will be restored as soon as the part arrives. In the meantime, emails and mobile phones are the best way to reach everyone working out of the Kimberton Office. We apologize for any inconvenience this may cause.
What’s The Latest On Carbon Capture and Control?
A public hearing was held today, February 6, 2014, concerning U.S. EPA’s proposed New Source Performance Standards (NSPS) for emissions of carbon dioxide (CO2) from new electric utility steam generating units (EGUs), which were published by U.S. EPA in the Federal Register on January 8, 2014. If the rule is finalized as proposed, new large natural gas-fired turbines would need to meet a limit of 1,000 pounds of CO2 per megawatt-hour, while new small natural gas-fired turbines would need to meet a limit of 1,100 pounds of CO2 per megawatt-hour. New coal-fired units would need to meet a limit of 1,100 pounds of CO2 per megawatt-hour, and would have the option to meet a more stringent limit if they choose to average emissions over multiple years. The January 8, 2014 Federal Register notice also proposes amendments to 40 CFR Part 60, Subpart Da (Standards of Performance for Electric Utility Steam Generating Units) and 40 CFR Part 60, Subpart KKKK (Standards of Performance for Stationary Combustion Turbines) which, if finalized as proposed, would add new standards for CO2 to these existing standards.
Interested parties following the progression of this rulemaking may recall that U.S. EPA had initially proposed NSPS for emissions of CO2 from new power plants on March 27, 2012; however, when U.S. EPA failed to issue the final version of this rule within one (1) year of the original proposal, the March 27, 2012 proposed rule was terminated and U.S. EPA was required to re-propose, accept comments on, and finalize an entirely new version of the rule. U.S. EPA’s new proposal was released as a notice of proposed rulemaking on September 20, 2013 by U.S. EPA’s Office of External Affairs and Environmental Education (OEAEE) but it wasn’t officially published in the Federal Register until more recently on January 8, 2014. Despite ongoing criticism that carbon capture and sequestration (CCS) is cost prohibitive and years away from commercial deployment, the latest version of the proposed rule still requires partial implementation of CCS for new coal-fired plants as the Best System of Emission Reduction (BSER). One of the more recent arguments against the CCS requirement references the Bush-era Energy Policy Act of 2005 (EPAct), which specifically prohibits U.S. EPA from citing a technology as being “adequately demonstrated” if the technology has only been used at a facility receiving assistance under the Department of Energy’s Clean Coal Power Initiative (CCPI), or at a facility that is receiving an advanced coal project tax credit. The power plants with CCS that are cited in the proposed NSPS as the justification for CCS being ‘adequately demonstrated’ all received such assistance. Therefore, critics of the proposed new rule will claim that U.S. EPA has proposed standards which are beyond its authority. CCS critics had hoped that U.S. EPA’s Science Advisory Board (SAB) would weigh in with a similar opinion, but the SAB has voted unanimously not to review the new rule, on the grounds that the CCS requirement falls outside the rule’s scope and that many of the scientific concerns regarding CCS may be policy and legal matters, instead of an element of the proposed rule that would be under the jurisdiction of SAB review. To further complicate the issue, both critics and supporters of requiring CCS as a CO2 control technology are pursuing multiple legal challenges and political resolutions for their causes.
In addition to today’s public hearing, U.S. EPA is accepting written comments on the proposed rule until March 10, 2014. This controversial rulemaking is certain to generate a large amount of comments, and the CCS requirement will surely be a primary topic discussed at the hearing and in the comments U.S. EPA receives. So we can expect it will be quite some time until the matter is resolved.
