Daily Rules, Proposed Rules, and Notices of the Federal Government
The information in this preamble is organized as follows:
Categories and entities potentially regulated by these final rules include:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. To determine whether your facility would be regulated by this action, you should examine the applicability criteria in 40 CFR 60.100 and 40 CFR 60.100a. If you have any questions regarding the applicability of this action to a particular entity, contact the person listed in the preceding
In addition to being available in the docket, an electronic copy of this final action is available on the World Wide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at
The EPA has created a redline document comparing the existing regulatory text of 40 CFR part 60, subpart Ja and the final amendments to aid the public's ability to understand the changes to the regulatory text. This document has been placed in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2007-0011).
Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of these final rules is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by November 13, 2012. Under section 307(b)(2) of the CAA, the requirements established by these final rules may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements.
Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for us to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding
This action finalizes amendments that were proposed on December 22, 2008, to address reconsideration issues related to the promulgation of new source performance standards (NSPS) for flares and process heaters on June 24, 2008. This action also lifts the stay that was granted on September 26, 2008 (73 FR 55751) and extended until further notice on December 22, 2008 (73 FR 78552) on the provisions at issue.
Table 1 presents a summary of major changes to the rule since it was first promulgated on June 24, 2008. The following discussion is a summary of major provisions of this rule.
Affected process heaters are those that were modified, reconstructed or constructed after May 14, 2007. For these affected sources, these final amendments include concentration-based nitrogen oxide (NO
For flares, these final amendments define a flare as a separate affected facility rather than a type of fuel gas combustion device. As such, these final amendments remove requirements for flares to comply with the performance standards for sulfur dioxide (SO
Affected flares are those that were modified, reconstructed or constructed after June 24, 2008. In general, a flare is modified if a connection is made into the flare header that can increase emissions from the flare. The NSPS specifically identifies certain connections to a flare that do not constitute a modification of the flare because they do not result in emissions increases.
The final amendments for flares include a suite of standards that apply at all times. This suite of standards requires refineries to: (1) Develop and implement a flare management plan; (2) conduct root cause analyses and take corrective action when waste gas sent to the flare exceeds a flow rate of 500,000 standard cubic feet per day (scfd) above the baseline flow or contains sulfur that, upon combustion, will emit more than 500 pounds (lb) of SO
The final amendments require that flares be equipped with flow and sulfur monitors except in cases where flares are used infrequently or are configured such that they cannot receive high sulfur gas. For flares that are configured such that they only receive inherently low sulfur gas streams, continuous sulfur monitors are not necessary because a root cause analysis will be triggered by an exceedance of the flow rate threshold long before they exceed the 500 lb SO
For infrequently used flares, the NSPS allows for less burdensome monitoring, consisting of monitoring the differential pressure between the flare header and the flare water seal to determine if a gas release to the flare has occurred. Any instance where the pressure upstream of the water seal (expressed in inches of water) exceeds the water seal height triggers a requirement to perform a root cause analysis and corrective action analysis, unless the discharge is related to flare gas recovery system compressor cycling or a planned startup or shutdown (of a refinery process unit or ancillary equipment connected to the flare) following the procedures in the flare management plan. The NSPS also contains an alternative compliance option for refinery flares located in the South Coast Air Quality Management District (SCAQMD) or the Bay Area Air Quality Management District (BAAQMD). An affected flare subject to 40 CFR part 60, subpart Ja may elect to comply with SCAQMD Rule 1118 or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of subpart Ja.
The provisions for flares and other fuel gas combustion devices (
Cost impacts for flares are presented in Table 2. The estimated total capital cost of complying with the final amendments to 40 CFR part 60, subpart Ja for flares is $460 million dollars (2006 dollars). The estimated annual cost, including annualized capital costs, is a cost savings of about $79 million (2006 dollars) due to the replacement of some natural gas purchases with recovered flare gas and the retention of intermediate and product streams due to a reduction in the number of malfunctions associated with refinery process units and ancillary equipment connected to the flare. Note that not all refiners will realize a cost savings since we only estimate that refineries with high flare flows will install vapor recovery systems. Although the rule does not specifically require installation of flare gas recovery systems, we project that owners and operators of flares receiving high waste gas flows will conclude, upon installation of monitors, implementation of their flare management plans, and implementation of root causes analyses, that installing flare gas recovery would result in fuel savings by using the recovered flare gas where purchased natural gas is now being used to fire equipment such as boilers and process heaters. The flare management plan requires refiners to conduct a thorough review of the flare system so that flare gas recovery systems are installed and used where these systems are warranted. As part of the development of the flare management plan, refinery owners and operators must provide rationale and supporting evidence regarding the flare waste gas reduction options considered. In addition, consistent with Executive Order 13563 (Improving Regulation and Regulatory Review, issued on January 18, 2011), for facilities implementing flare gas recovery, we are finalizing provisions that would allow the owner or operator to reduce monitoring costs and the number of root cause analyses, corrective actions, and corresponding recordkeeping and reporting they would need to perform. The costs calculated for this rule, however, do not account for potential savings due to these provisions (reduced monitoring, root cause analysis, etc.). We estimate that the final requirements for flares will reduce emissions of SO
We estimate the monetized benefits of this final regulatory action for all flares to be $260 million to $580 million (3-percent discount rate) and $240 million to $520 million (7-percent discount rate for health benefits and 3-percent discount rate for climate benefits). For small flares only, we estimate the monetized benefits are $170 million to $410 million (3-percent discount rate) and $150 million to $370 million (7-percent discount rate for health benefits
Although this final rule provides refiners with some additional compliance options and removes some requirements, such as the long-term H
Section 111(b)(1)(A) of the Clean Air Act (CAA) requires the EPA to establish federal standards of performance for new, modified and reconstructed sources for source categories which cause or contribute significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. The standard of performance must reflect the application of the best system of emission reductions (BSER) that (taking into consideration the cost of achieving such emission reductions, any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated (CAA section 111(a)(1)). If it is not feasible to prescribe or enforce a standard of performance, the Administrator may instead promulgate a design, equipment, work practice or operational standard, or a combination of these types of standards (CAA section 111(h)(1)). Since 1970, the NSPS have been successful in achieving long-term emissions reductions in numerous industries by assuring cost-effective controls are installed on newly constructed, reconstructed or modified sources.
The level of control prescribed by CAA section 111 historically has been referred to as “Best Demonstrated Technology” or BDT. In order to better reflect that CAA section 111 was amended in 1990 to clarify that “best systems” may or may not be “technology,” the EPA is now using the term “best system of emission reduction” or BSER in its rulemaking packages. See,
Section 111(b)(1)(B) of the CAA requires the EPA to periodically review and, as appropriate, revise the standards of performance to reflect improvements in methods for reducing emissions. As a result of our periodic review of the NSPS for petroleum refineries (40 CFR part 60, subpart J), we proposed amendments to the current standards of performance and separate standards of performance for new process units (40 CFR part 60, subpart Ja) (72 FR 27278, May 14, 2007) and we subsequently promulgated those amendments and new standards (73 FR 35838, June 24, 2008). Following promulgation, we received three separate petitions for reconsideration from: (1) The American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA) and the Western States Petroleum Association (WSPA) (collectively referred to as “Industry Petitioners”); (2) HOVENSA, LLC (“HOVENSA”); and (3) the Environmental Integrity Project, Sierra Club and Natural Resources Defense Council (collectively referred to as “Environmental Petitioners”). On September 26, 2008, the EPA issued a
In the September 26, 2008,
In this action, we are finalizing the amendments for which we granted reconsideration and a stay as outlined in the September 26, 2008, notice and for which we proposed amendments on December 22, 2008. We are also addressing certain other minor issues raised by Industry Petitioners in this action, as discussed later in this preamble. We will take action on all of the remaining issues raised by Petitioners for reconsideration in future notices.
We received a total of 22 comments from the following groups on the proposed amendments during the public comment period: (1) Refineries, industry trade associations and consultants; (2) state and local environmental and public health agencies; (3) environmental groups; and (4) other members of the public. These final amendments reflect our full consideration of all of the comments we received. Detailed responses to the comments not included in this preamble, as well as more detailed summaries of the comments addressed in this preamble, are contained in
In summary, major comments on the proposed process heater requirements were related to the proposed NO
Major comments on the proposed requirements for flares were related to the definition of flare modification for purposes of triggering applicability to this rule, the proposed removal of the flare flow limit, clarification of flare monitoring requirements and clarification of the differences between the requirement for flares and the requirements for other fuel gas combustion devices. We address these comments by clarifying the definition of flare modification and by expanding the list included in the December 22, 2008, proposal, which specifies certain connections that do not constitute a modification of the flare because they do not result in emissions increases. We are finalizing the proposed removal of the flare flow limit and instead, we are promulgating a suite of work practice standards that apply to affected flares. Based on comments received on the December 22, 2008 proposal, we are finalizing definitions of “fuel gas combustion device” and “flare” to specify that a flare is a separate affected facility rather than a type of fuel gas combustion device. We are also finalizing amendments to clarify certain monitoring requirements and to provide additional monitoring alternatives under certain circumstances.
NSPS for petroleum refineries (40 CFR part 60, subpart J) apply to the affected facilities at the refinery, such as fuel gas combustion devices (which include process heaters, boilers and flares), that commence construction, reconstruction or modification after June 11, 1973, but on or before May 14, 2007 (on or before June 24, 2008 for flares). The NSPS were originally promulgated on March 8, 1974, and have been amended several times. In this action, we are promulgating technical clarifications and corrections to subpart J.
New standards of performance for petroleum refineries (40 CFR part 60, subpart Ja) apply to flares that commence construction, reconstruction or modification after June 24, 2008, and other affected facilities at petroleum refineries, including process heaters and other fuel gas combustion devices that commence construction, reconstruction or modification after May 14, 2007. In this action, we are finalizing amendments to subpart Ja to address the issues raised by Petitioners regarding flares and process heaters. We are also finalizing technical corrections to subpart Ja for certain issues that were identified by Industry Petitioners in their August 21, 2008, supplement to their original administrative reconsideration request (Docket Item No. EPA-HQ-OAR-2007-0011-0246).
The following sections summarize the amendments in both 40 CFR part 60, subpart J and 40 CFR part 60, subpart Ja. Section IV contains the rationale for these amendments, while the amendments themselves follow the preamble.
The final amendments add a new paragraph to 40 CFR 60.100 to allow 40 CFR part 60, subpart J affected sources the option of complying with subpart J by following the requirements in 40 CFR part 60, subpart Ja. The subpart Ja requirements are at least as stringent as those in subpart J, so providing this option will allow all process units in a refinery to follow the same requirements and simplify compliance. We are also removing the reference to 40 CFR 60.101a from the description of the applicability dates in 40 CFR 60.100(b) so as not to cause confusion over the definition of “flare” in subpart J. We are finalizing a correction to the value and units (in the metric system) for the allowable incremental rate of particulate matter (PM) emissions in 40 CFR 60.106(c)(1). We amended the units for this constant in 40 CFR 60.102(b) on June 24, 2008, and we are now correcting 40 CFR 60.106(c)(1) accordingly. Finally, we are finalizing a definition of “fuel gas” that incorporates the same clarifications regarding vapors from wastewater treatment units and marine tank vessel loading operations identified in the subpart Ja definition of “fuel gas” (described later in this preamble).
We proposed several amendments to the standards of performance for process heaters, including adding emission limits in units of lb/MMBtu, extending the emission limit averaging time from 24 hours to 365 days, raising the emission limit for modified and reconstructed forced draft process heaters and raising the emission limit for co-fired process heaters. After consideration of all of the public comments and our own additional analyses, we are finalizing the process heater requirements, as described in this section.
Table 3 presents a comparison of the proposed and final 40 CFR part 60, subpart Ja amendments for process heaters. The final amendments include four subcategories of process heaters: (1) Natural draft process heaters; (2) forced draft process heaters; (3) co-fired natural draft process heaters; and (4) co-fired forced draft process heaters. At proposal, all co-fired process heaters were included in one subcategory, for a total of three process heater subcategories, but, based on emissions data from co-fired process heaters, we divided natural draft and forced draft co-fired process heaters into separate subcategories with different emissions limits.
For each of the first two subcategories, the final amendments include a concentration-based NO
For the second subcategory, forced draft process heaters, the concentration-based NO
For each of these subcategories, a process heater need only meet either the concentration-based NO
As proposed, initial compliance with the heating value-based emissions limits will be demonstrated by conducting a performance evaluation of the continuous emission monitoring system (CEMS) in accordance with Performance Specification 2 in appendix B to 40 CFR part 60, with EPA Method 7 of 40 CFR part 60, appendix A-4 as the Reference Method, along with fuel flow measurements and fuel gas compositional analysis. The NO
The third and fourth subcategories of process heaters are co-fired process heaters. A co-fired process heater is a process heater that employs burners that are designed to be supplied by both gaseous and liquid fuels. As described in more detail in section IV.A of this preamble, co-fired process heaters do not include gas-fired process heaters that have emergency oil back-up burners. There are two compliance options for each subcategory of co-fired process heaters: (1) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive operating day rolling average basis; and (2) a source-specific daily average emissions limit. Unlike gas-fired process heaters, the owner or operator of a co-fired process heater must choose one emissions limit and show compliance with that limit. For co-fired natural draft process heaters, the daily average emissions limit is based on a limit of 0.06 lb/MMBtu for the gas portion of the firing and 0.35 lb/MMBtu for the oil portion of the firing. For co-fired forced draft process heaters, the daily average emissions limit is based on a limit of 0.11 lb/MMBtu for the gas portion of the firing and 0.40 lb/MMBtu for the oil portion of the firing. These limits are different than proposed, based on a re-evaluation of BSER with new data received during the public comment period. All of the requirements for emissions monitoring, recordkeeping and reporting for co-fired process heaters are the same as for the other process heater subcategories.
We are also finalizing an alternative compliance option that allows owners and operators to obtain EPA approval for a site-specific NO
Finally, we note that the emissions limits for forced draft and natural draft gas-fired process heaters are based on the performance of ultra-low NO
We are finalizing the proposed clarification that owners and operators of process heaters in any subcategory with a rated heating capacity of less than 100 million British thermal units per hour (MMBtu/hr) have the option of using CEMS. The final rule states that owners and operators of process heaters subject to 40 CFR part 60, subpart Ja should use CEMS to demonstrate compliance unless the heater is equipped with combustion modification-based technology (low-NO
We proposed several amendments to the standards of performance for flares, including, but not limited to, amending the flare modification provision, removing the numerical limit on the flow rate to the flare, revising the flare management plan requirements to include a list of connections to the flare and an identification of baseline conditions, clarifying when a root cause analysis is required, revising the sulfur and flow monitoring requirements and providing additional time for compliance. After consideration of all of the public comments, and our own additional analyses, we are finalizing the flare requirements, as described in this section.
We did not propose to revise the definitions of “fuel gas combustion device” and “flare” on December 22, 2008. However, based on public comment and changes to the flare requirements, as described later in this section, we have decided to finalize revisions to these definitions to specify that, for purposes of 40 CFR part 60, subpart Ja, a flare is a separate affected facility rather than a type of fuel gas combustion device. This change makes clearer the differences between the requirements for flares and the requirements for fuel gas combustion devices, particularly in terms of sulfur and flow rate monitoring requirements and thresholds for root cause analyses and corrective action analyses. We are also making corrections, as needed, in numerous paragraphs throughout subpart Ja for consistency with the amended definitions (
We are finalizing the flare modification provision in 40 CFR 60.100a(c), as described below, to specify certain connections to a flare that do not constitute a modification of the flare because they do not result in emissions increases. On December 22, 2008, we proposed that the following types of connections to a flare would not be considered a modification of the flare: (1) Connections made to install monitoring systems to the flares; (2) connections made to install a flare gas recovery system; (3) connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded; and (4) replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved. We are finalizing those proposed amendments and also adding the following types of connections to the list of connections to flares that are not modifications of flares: (1) Connections between flares; (2) connections for flare gas sulfur removal; and (3) connections made to install redundant flare equipment (such as a back-up compressor). We are also clarifying one of the proposed exemptions to indicate that connections made to upgrade or enhance components of flare gas recovery systems (
We are not finalizing the proposed amendment to provide additional time for flares that need to install additional amine scrubbing and amine stripping columns to meet the requirement to limit the long-term concentration of H
We are promulgating final amendments for flares that include a suite of standards that apply at all times that are aimed at reducing SO
In addition, we are specifying that, if a discharge exceeding either or both of the SO