In accordance with a federal court order, the United States Environmental Protection Agency (USEPA) signed a final rule on October 1, 2015, revising the National Ambient Air Quality Standards (NAAQS) for ground level ozone, lowering the primary and secondary standards to 70 ppb, a decrease of 5 ppb from the 2008 ozone NAAQS. The USEPA believes that this standard should be attainable for most areas based on the implementation of other large regulations recently promulgated, e.g., Tier 3 vehicle standards, the Mercury and Air Toxics Standards (MATS) and the Clean Power Plan. The rule was published in the Federal Register on October 26, 2015, and becomes effective on December 28, 2015.
Based on clinical studies and analyses of the effect of ozone exposure, the USEPA concluded a primary ozone NAAQS of 70 ppb is sufficient to protect public health with an adequate margin of safety. Likewise, the USEPA concluded that a secondary ozone NAAQS of 70 ppb is sufficient to protect public welfare, e.g., protection of the forests in Class I areas. The averaging time and form of the standards will remain the same. Compliance is demonstrated when the fourth-highest daily maximum 8-hour ozone concentration per year, averaged over three years, is less than or equal to 70 ppb. The USEPA deemed the 70 ppb standards to be “requisite to protect public health and welfare,” meaning that the level is neither more nor less stringent than necessary.
The implementation timeline for the 2015 ozone NAAQS is as follows:
- October 2016 – States recommend non-attainment designations to USEPA, based on monitoring data from the previous three-year period (2013-2015).
- October 2017 – USEPA makes final non-attainment designations based on monitoring data from 2014-2016.
- 2020-2021 – State Implementation Plans (SIPs) due (date dependent on severity of non-attainment designation).
- 2020-2037 – States must comply with the standard (date dependent on severity of non-attainment designation).
As presented above, states are required to submit recommended non-attainment designations to USEPA by October 2016, based on monitoring data from the previous three-year period. USEPA plans to issue guidance documents in early 2016 to facilitate the designation process.
Several states in the western U.S. have expressed concern regarding the impact of background ozone concentration on ambient air quality and counties’ abilities to demonstrate compliance with the more stringent ozone standards. The USEPA believes that background ozone will not prevent areas from attaining the 70 ppb ozone standards; however, to address this concern, USEPA plans to update the Exceptional Events Rule, which allows states to exclude “uncontrollable pollution,” such as increased ozone levels due to wildfires. Additionally, the USEPA plans to issue a white paper on background ozone and hold a stakeholder workshop. The USEPA will also work with states to address interstate transport of ozone and ozone precursors, especially in areas affected by high background concentrations of ozone due to long-range transport of ozone from other countries and wildfires.
The final regulation also provides a transition mechanism for PSD permitting projects currently underway via a grandfathering provision. Projects subject to this provision must demonstrate compliance with the 75 ppb ozone NAAQS standards from 2008 but will not be required to demonstrate compliance with the 2015 standards. This will allow these projects to proceed without the significant delay associated with preparation of a new compliance demonstration. In order to qualify for the provision, the facility must have achieved one of the following milestones:
- The permitting agency formally determined the application to be complete as of October 1, 2015; or
- The public notice for a draft permit or preliminary determination will have been published prior to December 28, 2015, the date the revised ozone standards become effective.
For 33 states and regions, the USEPA has also increased the length of the ozone monitoring season to address findings that ozone levels can be elevated earlier in the spring and later in the fall than the current monitoring time frame. This extension ranges from the addition of one month for 22 states and the District of Columbia to an additional seven months for Utah. The revised standard also requires that ozone monitors located at multi-pollutant NCore monitoring sites operate year-round. These changes will become effective January 1, 2017.
Additional changes to the NAAQS include updating the Air Quality Index (AQI), streamlining and modernizing the Photochemical Assessment Monitoring Stations (PAMS) network, and updating the Federal Reference Method for ozone to include an additional method for measuring ozone in outdoor air.
Many state agencies will host stakeholder meetings over the next year as they begin to identify potential ozone non-attainment areas. Check your state’s website to follow their activities.
If you have any questions about the 2015 ozone NAAQS and their implications to your facility, please contact either Amy Ritts (firstname.lastname@example.org; 888-598-6808). More information on the ozone standards is available at http://www3.epa.gov/airquality/ozonepollution/actions.html.
On November 25, 2014 the USEPA (EPA) proposed to lower the primary and secondary national ambient air quality standards (NAAQS) for ground-level ozone (the main component of smog). The proposed revision was published in the Federal Register on December 17, 2014, and comments were accepted through March 17, 2015. The final rule will be issued by October 1, 2015.
Primary NAAQS establish pollutant concentrations intended to protect public health with an “adequate margin of safety,” as required by the Clean Air Act. Secondary NAAQS are set to protect the public welfare (such as trees, plants and ecosystems) from “any known or anticipated adverse effects.” In accordance with the Clean Air Act, the EPA is required to review the NAAQS every 5 years to determine whether the standards remain “requisite to protect public health” (i.e., neither more or less stringent than necessary). The primary and secondary ozone NAAQS were last set in 2008, when the 75 ppb, 8-hour standard became effective.
The EPA proposed that the current primary ozone NAAQS of 75 ppb is no longer sufficient to protect public health with an adequate margin of safety and should be lowered into the range of 65 to 70 ppb. The averaging time and form of the standard will remain the same, with compliance demonstrated when the fourth-highest daily maximum 8-hour ozone concentration per year, averaged over 3 years, is less than or equal to the level of the standard. The EPA accepted comments on setting the standard as low as 60 ppb, as well as retaining the current standard of 75 ppb. Likewise, the EPA proposed that the current secondary ozone NAAQS is no longer sufficient to protect public welfare and should be revised to between 13 and 17 ppm-hrs, as defined in terms of seasonal index W126, which is equivalent to between 65 to 70 ppb. The EPA accepted comments on defining the level of protection as low as 7 to 13 ppm-hrs, as well as retaining the existing standard.
Based on the three-year average of monitoring data collected in 2011 through 2013, 358 counties (shown on the map below) would violate the NAAQS if lowered to 70 ppb and 200 additional counties (558 counties, total) would violate the NAAQS if lowered to 65 ppb. (Please note: This includes calendar year 2012 data which reflects increased ozone formation due to above-average temperatures and below-average humidity in central and eastern parts of the country. The final attainment designations will be based on monitoring data from the three-year period of 2014 through 2016, and it is possible that some of the counties that are projected to be in violation of the new standard will actually be in attainment.)
If a county is designated as nonattainment, new major sources or existing major sources planning to make a major modification in that area will become subject to nonattainment new source review (NNSR) considerations for ozone. There are many challenges associated with NNSR permitting including evaluation and implementation of lowest available emission rate (LAER). With LAER, the highest level of control is required without regard to cost. In addition, facilities are required to achieve a net reduction of the nonattainment pollutant emissions by obtaining emission offsets. Offsets can be expensive due to high demand and limited quantity. Facilities which have preconstruction permit applications well under the review process will be grandfathered at the time the final standard is issued.
The EPA has also proposed extending the monitoring season in 33 states to address findings that ozone levels can be elevated earlier in the spring and later in the fall than the current monitoring season time frame. This extension ranges from the addition of one month for some states to requiring year-round monitoring for others. The proposed effective date for the extended monitoring season is January 1, 2017.
The current timeline for EPA issuing a final regulation either leaving the NAAQS at the current standard or lowering the value, as well as all associated activities, is as follows:
- October 2015 – EPA finalizes standard
- October 2016 – States recommend non-attainment designations to EPA
- October 2017 – EPA makes final non-attainment designations
- 2020-2021 – State Implementation Plans (SIPs) due (date dependent on severity of non-attainment designation
- 2020-2037 – States must comply with the standard (date dependent on severity of non-attainment designation)
On March 17, 2015, the U.S. Senate and the House of Representatives introduced bills to block the proposed changes to the ozone NAAQS based largely on economic concerns. The bills, presented by senators Joe Manchin (D-WV) and John Thune (R-SD) and Representatives Pete Olson (R-TX) and Robert E. Latta (R-OH) would prevent the EPA from lowering the standard until at least 85% of U.S. counties that are currently not in attainment with the 2008 standard attain the 75 ppb ground-level ozone concentration level. It is unclear what effect these bills may have, considering the Supreme Court’s 2001 affirmation in Whitman v. American Trucking Associations, Inc. that the Clean Air Act “unambiguously bars cost considerations from the NAAQS setting process.” However the bills help to focus attention on the importance of economic costs when the EPA and states work to implement new air quality standards. CEC will follow how the proposed bills will impact EPA’s deadline to finalize the rule as well as any impacts on the final standards set in the final rule.
If you have any questions about the proposed changes to the ground-level ozone NAAQS and their implications to your facility, please contact either Amy Ritts (email@example.com; 888-598-6808). More information on the proposed standards is available at http://www.epa.gov/glo/actions.html.
2011 was a busy year for those attempting to stay abreast of air quality issues affecting the oil and gas industry in Pennsylvania. In recent presentations to the PA Chamber of Business and Industry and the Marcellus Shale Coalition, Joyce Epps, PADEP’s Director of Air Quality, discussed PADEP’s intent to require natural gas facility owner/operators to submit an atmospheric emission inventory data by March 1, 2012. This is just the latest in a series of state and federal air quality compliance issues that have been pertinent to the oil and gas industry. As 2012 gets underway, expect to hear more about emission inventories, general permits, plan approval exemptions, source aggregation, NSPS/NESHAPS, and greenhouse gas reporting. If your head is spinning, here is an update on some key air topics:
1) PADEP Atmospheric Emission Inventories
PADEP is rolling out its first emissions inventory program for the natural gas industry. Initial indications are that it will be modeled after the Wyoming Department of Environmental Quality approach. PADEP sent initial notification letters to 99 operators on 12/6/11 with the intent that 2011 inventories be submitted by 3/1/12. Criteria pollutants (e.g., carbon monoxide and nitrogen dioxide) and hazardous air pollutants (e.g., benzene and formaldehyde) from point sources (e.g., dehydrators and heaters), fugitive or area sources (e.g., leaking components and impoundments), and mobile sources (e.g., on- and off-road engines) are expected to be included. An Excel-based Shale Air Emissions Data Management System is being developed and the publicly-available Oil and Gas Reporting Electronic (OGRE) System will be modified to accommodate the reporting of this information. Training is expected to be offered by PADEP in February 2012. Additional materials can be found on PADEP’s website here. Industry representatives are hopeful that an extension will be granted for delivery of the first reports.
2) General Permit GP-5 – Natural Gas Production Facilities
Use of GP-5 expedites the permitting of certain natural gas activities. The permit was last updated on 3/17/11 although no changes were made to the applicability of the permit or the associated emission limits. The main change to the permit was a new condition that allows the applicant to limit the maximum emissions (i.e., potential to emit) of a source. The biggest changes though were to the application itself which expanded from two pages to nine. The new application requires significantly more detail including serial numbers for equipment, design parameters for control devices, and compliance demonstration methods. With the development of EPA’s new NSPS and NESHAPS (see Item 6 below), PADEP plans to issue more substantive changes to GP-5 in early 2012. Watch for the opportunity to submit comments during another 45-day window when proposed modifications are published.
3) General Permit GP-11 – Nonroad Engines
Proposed changes to GP-11 were published in the PA Bulletin on 10/30/10. PADEP included a provision to operate engines at temporary locations provided written notification is made to the municipality and PADEP five days prior to the change in location. PADEP also proposed to require that an operations report be submitted within 30 days of completing work at each temporary location. PADEP received comments from 1,122 parties prior to the comment period that closed on 5/26/11 and PADEP is still in the process of developing a comment and response document. Possible changes to GP-11 are closely tied to proposed revisions to Exemption #38 on the PADEP Plan Approval Exemption List.
4) Plan Approval Exemption #38
Certain oil and gas exploration and production facilities were exempt from Plan Approval requirements under Exemption #38 of the 7/26/03 list of Plan Approval exemptions. A draft revision to that list was published on 4/16/10 which included the addition of several caveats to Exemption #38 that make it more difficult to obtain the exemption. The public comment period closed on 5/26/11 by which time the agency had received comments on Exemption #38 from 1,225 parties. Industry advocates are hopeful that the exemption will be tailored to enable nonroad engines that would otherwise be subject to GP-11 to be exempt from permitting requirements altogether. PADEP is considering its response to these comments in combination with its work on GP-11.
5) Source Aggregation Guidance
PADEP published its final Guidance for Performing Single Stationary Source Determinations for Oil and Gas Industries on 10/22/11 (41 Pa.B. 5719). The comment period for that guidance closed on 11/21/11. PADEP is in the process of responding to comments from 364 parties, perhaps most notable among them being Diana Esher, U.S. EPA Region III Air Protection Division Director. Ms. Esher stated that, “We disagree with the policy pronouncements in the PADEP guidance which differ from established federal law and the Commonwealth’s own State Implementation Plan (SIP) and regulations by attempting to emphasize proximity and ‘common sense notion of a plant’ above other factors including conducting case-by-case analysis.” Through six pages of detailed comments, EPA delineates multiple disagreements with PADEP’s guidance. Ms. Esher states that PADEP indicates an intent “…to change the manner in which regulations that have been adopted as part of the…SIP and that are now federal law will be implemented.” Ms. Esher states that “this is problematic,” in that the SIP becomes federal law once approved by EPA, not state law. In concluding, Ms. Esher was clear that EPA will be paying close attention to PADEP’s source aggregation determinations.
Proposed air emission standards for the oil and natural gas industry were published in the Federal Register on 8/23/11. As drafted, these rules will apply to production and processing (drilling and well completions following hydraulic fracturing, producing wells, gathering lines, gathering and boosting compressors, gas processing plants) and transmission and storage (transmission compressor stations, transmission pipeline, underground storage). Various industry groups including the American Petroleum Institute, the Gas Processors Association, and the Marcellus Shale Coalition submitted comments prior to the close of the comment period in late November 2011. Final rules, expected by 2/28/12, will be automatically adopted in their entirety in the Pennsylvania Code.
7) 40 CFR 98, Subpart W Greenhouse Gas Reporting
Subpart W was published at the end of 2010 and obliged affected facilities to begin gathering data in 2011 for initial GHG reports due in 2012 (see CEC’s prior blog posting). The Subpart has gone through several modifications since it was originally published, the most significant of which was an allowance for the use of best available monitoring methods (BAMM) for all of 2011. Use of BAMM is currently permitted through June of 2012 providing the designated representative e-filed a Notice of Intent prior to 1/3/12. Affected parties are encouraged to monitor changes in the rule for revisions to emission estimation methodologies and other technical revisions. The current due date for the 2011 reports is 9/28/12.
CEC will be following these topics and will provide periodic updates as they develop. In the meantime, if you are unclear as to how any of these issues may affect your operations, please contact CEC’s natural gas air quality expert Kris Macoskey at 800-365-2343 or by email at firstname.lastname@example.org.
U.S. EPA continues to roll out new subparts and revisions to the Greenhouse Gas (GHG) Reporting Rule (40 CFR 98). This time we take a look at Subpart W – Petroleum and Natural Gas Systems which was published in the November 30, 2010 Federal Register. GHG emissions from this industry are generated by combustion (e.g., heaters, engines, furnaces, etc.), fugitive equipment leaks, and process vents.
As with the other 40 CFR 98 subparts, facilities that emit 25,000 metric tons (mt) or more of carbon dioxide equivalents (CO2e) per year must report. However, the definition of a facility is slightly more complicated here than for other subparts.
First, there are eight segments of the petroleum and natural gas industry that need to be considered. Each industry segment is defined in the rule (see §98.230) and more detailed descriptions can be found in the 144-page Background Technical Support Document. The eight industry segments are:
- Offshore petroleum and natural gas production;
- Onshore petroleum and natural gas production;
- Natural gas processing plants;
- Natural gas transmission compression;
- Underground natural gas storage;
- Liquefied natural gas (LNG) storage;
- LNG import and export equipment; and
- Natural gas distribution.
The next step in defining a facility under Subpart W is to consider the 21 categories of emission sources that have been identified within the eight industry segments. For example, the onshore petroleum and natural gas production facility (Segment 2) includes 19 different types of emission sources that need to be inventoried to determine if the annual 25,000 mt CO2e applicability threshold is exceeded (e.g., dehydrator vents, flare stacks, and well testing vents).
For six of the industry segments, the facility definition stops there. One simply accounts for all of the sources located on contiguous property or under common ownership/control and for which calculation approaches have been provided in the rule. Two of the industry segments require one more step to define the facility.
For the Onshore Petroleum and Natural Gas Production industry segment, the rule defines a facility as all of the equipment on or associated with a well pad that is under common control or ownership and that is located within a single hydrocarbon basin, as defined by the American Association of Petroleum Geologists Geologic Provinces Code Map. (This 1991 publication is not provided by EPA but can be obtained from AAPG here. As one might imagine, geologic provinces cover large areas (e.g., most of Pennsylvania as well as parts of New York, West Virginia, and five other southern states is covered by Code 160A – Appalachian Basin Eastern Overthrust Area). This means that operations at multiple well pad locations will have to be aggregated for applicability determinations and reporting purposes.
The facility definition for the Natural Gas Distribution industry segment is not based on geography. Instead, EPA has simply included “all distribution pipelines, metering stations, and regulating stations” that physically deliver natural gas to end users as operated by a single local distribution company (LDC). The caveat relative to an LDC is that it is regulated as a separate operating company by a public utility commission or it is operated as an independent municipally-owned distribution system.
The eight industry segments and the associated 21 categories of emission sources for which GHG calculation procedures have been developed are summarized in the following table.
Summary of Source Types by Industry Segment
|Source Type||Industry Segments
(see list above)
|Natural gas pneumatic device venting||X||X||X|
|Natural gas driven pneumatic pump venting||X|
|Acid gas removal vent||X||X|
|Well venting for liquids unloading||X|
|Gas well venting during well completions and workovers with hydraulic fracturing||X|
|Gas well venting during well completions and workovers without hydraulic fracturing||X|
|Blowdown vent stacks||X||X||X||X|
|Onshore production storage tanks||X|
|Transmission storage tanks||X|
|Well testing venting and flaring||X|
|Associated gas venting and flaring||X|
|Centrifugal compressor venting||X||X||X||X||X||X|
|Reciprocating compressor and packing venting||X||X||X||X||X||X|
|Other emissions from equipment leaks||X||X||X||X||X||X||X|
|Population count and emissions factor||X||X||X||X||X|
|Vented equipment leaks and flare emissions identified in BOEMRE GOADS study||X|
|Enhanced oil recovery hydrocarbon liquids dissolved CO2||X|
|Enhanced oil recovery injection pump blowdown||X|
|Onshore petroleum and natural gas production and natural gas distribution combustion emissions||X||
EPA has developed extensive checklists that describe in detail what needs to be monitored at the seven onshore industry segments. For example, Natural Gas Distribution facilities (Segment 8 ) need to account for the total number of leaking control valves and the operating time of leaking orifice meters, among many other things. Emission calculation methods specified in the rule include engineering estimates, direct measurement, leak detection emission factors, and equipment counts with population emission factors.
The rule requires affected facilities to develop Monitoring Plans in accordance with the General Provisions by April 1, 2011. Best available monitoring methods (BAMM) will be allowed for certain data gathering requirements for periods up through December 31, 2011. Requests to use BAMM for extended periods must be submitted to EPA in accordance with the timing requirements specified in the rule (either April 30 or September 30, 2011).
CEC recommends that facilities carefully review the regulation, the EPA guidance, the applicability tools, and the emission estimation tools available at EPA’s site on their Greenhouse Gas Reporting Program page. If you are unclear about how this rule affects your facility, please contact one of CEC’s GHG experts: Kris Macoskey, 800-365-2324, email@example.com. You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.
U.S. Environmental Protection Agency Proposes Transport Rule To Reduce Interstate Transport of Air Pollution
On July 6, 2010 the U.S. Environmental Protection Agency (EPA) proposed a rule to address interstate transport of air pollution. This proposed rule would replace the 2005 Clean Air Interstate Rule (CAIR). The proposed rule, known as the Transport Rule, would require 31 states and the District of Columbia to improve air quality by reducing emissions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from electric generating power plants that contribute to ozone and fine particulate pollution in other states. SO2 and NOx react in the atmosphere to form fine particulate matter less than 2.5 micron (PM2.5). NOx also contributes to ozone formation. The SO2 and NOx are then transported across states, making it difficult for states downwind to comply with National Ambient Air Quality Standards (NAAQS).
This proposed rule would clarify state obligations to reduce pollution affecting other states under the Clean Air Act by defining “significant contribution” and “interfere with maintenance.” In defining these obligations, the EPA proposes to consider the magnitude of a state’s contribution, the air quality benefits of reductions, and the cost of controlling pollution from various sources.
The emission reductions are scheduled to begin in 2012, within one year after the rule is finalized. EPA estimates that by 2014, in conjunction with other state and federal programs, that emissions of SO2 and NOx from power plants would be reduced by 71 and 52 percent, respectively from 2005 levels. Compared to 2005, EPA estimates that by 2014 this proposal and other federal rules would lower emissions by:
- 6.3 million tons per year of SO2
- 1.4 million tons per year of NOX, including 300,000 tons per year of NOX during the ozone season.
The proposed rule is expected to annually cost electric utilities and consumers $2.8 billion, but is expected by EPA to yield $120 to $290 billion in annual health and welfare benefits in 2014. EPA also estimates that between 14,000 to 36,000 premature deaths will be avoided.
The rule specifies that twenty-eight states would be required to achieve reductions in both SO2 and NOx emissions to assist downwind states in meeting attainment with the annual and 24-hour PM2.5 standards. Furthermore, the rule requires twenty-six states to reduce NOx emissions during the ozone season to assist downwind states in reducing ground-level ozone concentrations in order to comply with the ground-level ozone standard. The following map identifies the states subject to the rule and the emissions to be controlled.
EPA’s approach for reducing SO2 and NOX emissions in states covered by this rule is to set a pollution limit (or budget) for each of the 31 states and the District of Columbia. This approach allows limited interstate trading among power plants but assures that each state will meet its pollution control obligations.
EPA is also taking comments on two alternative approaches. The first alternative would set a pollution limit or budget for each state. This option allows trading only among power plants within a state. The second alternative would set a pollution limit for each state and specify the allowable emission limit for each power plant and allow some averagingof the emissions.
To assure emissions reductions, EPA is proposing Federal Implementation Plans, or FIPs, for each of the states covered by this rule. The FIPs would put in place requirements necessary to reduce pollution in the covered states that significantly contributes to nonattainment of or interferes with maintenance of the national ambient air quality standards in other states.
States may choose to develop a State Implementation Plan (SIP) to achieve the required reductions, replacing its federal plan.
In order to achieve emission reductions outlined in the Transport Rule, power plants may be required to:
- operate already installed air pollution control equipment more frequently,
- use low sulfur coal, or
- install control equipment such as low NOx burners, Selective Catalytic Reduction, or Flue Gas Desulfurization.
If your facility will be affected by the Transport Rule, or if you have questions regarding the rule, please contact CEC’s St. Louis office at 866-250-3679.