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.