Author: Kristian Macoskey, QEP
Update — EPA issues final New Source Performance Standards for Oil and Gas with significant new compliance requirements
On June 3, 2016, U.S. Environmental Protection Agency (EPA) finalized amendments to the Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (Quad O) and a new subpart at 40 CFR 5360a et seq. (Quad Oa) for post-September 18, 2015, affected facilities. As noted in a previous CEC blog on this topic, U.S. EPA received nearly one million comments following the initial proposal. The new Quad Oa rule establishes emission standards for both methane and volatile organic compounds (VOC) at natural gas and oil well sites, production gathering and boosting stations, natural gas processing plants, and compressor stations. There are several new requirements for oil and natural gas production-related activities in these new federal rules, and it is important to understand how these rules might impact ongoing compliance activities under existing state rules and permit requirements already in effect. In this update, we focus on two of these new requirements due to their history and interrelatedness.
It is clear in reading both the proposed and final rules that U.S. EPA has expanded its understanding of oil and natural gas operations, particularly with respect to upstream E&P. Notably, the requirement for a professional engineer (PE) to evaluate and certify closed vent system design brings a new level of scrutiny borne out of a consent decree with a major oil and gas producer, and placed into practice in both the September 2015 Compliance Alert and the ongoing enforcement initiative targeting “energy extraction activities.” Not only is this new requirement intended to bring industry resources to bear on what the Agency views as a significant issue, but it also attaches professional liability to any subsequent violations attributed to closed vent system design. Further, with additional attention being focused on closed vent system design, the next obvious move on the Agency’s part was either construction practices (which are in many cases guided by industry consensus standards) or the operator’s preventative maintenance program.
From an air pollution control perspective, one focus of an upstream E&P maintenance program is to minimize or eliminate fugitive emissions from production facility equipment. As addressed by the industry during the comment period, there is an economic incentive to minimize losses of otherwise saleable products. Rather than dictate the contents of a preventative maintenance program, the Agency has instead required operators to survey for and repair fugitive emissions at well sites. While not a maintenance program per se, the new rule will require operators to engage in some routine maintenance and communication planning to ensure that fugitive leaks discovered during a survey are repaired and verified within the allotted timeframe.
Many producers operating in the Utica and Marcellus plays already had some form of fugitive emissions survey requirements in effect, as does Colorado. In other states, this will be the first time operators will have to grapple with leak detection and repair programs. This new requirement will have a disparate impact on upstream E&P operators that do not have the resources to employ full-time environmental staff or purchase the equipment needed to perform these required fugitive leak surveys in-house.
A summary of the new requirements discussed above is provided here. In the meantime, if you have questions on any aspects of the NSPS for the oil and natural gas source category, please contact the post authors: Kris Macoskey (firstname.lastname@example.org), or Ben Blasingame (email@example.com).
For those interested in exploring this topic further:
Final NSPS OOOO and OOOOa rule from the Federal Register
U.S. EPA National Enforcement Initiatives
CEC’s previous blog: EPA Receives Nearly One Million Comments on Proposed New Source Performance Standards for Oil and Gas
On February 2, 2012, Governor Corbett signed into law Act 9 (P.L. 67, No. 9) codified at 35 Pa C.S. §7321. This rulemaking required the Pennsylvania Emergency Management Agency (PEMA) to adopt emergency regulations aimed at new and existing unconventional wells within the Commonwealth. The rulemaking was intended to enhance the ability of local governments to manage emergency response, establish Statewide standards for emergency response, and define standard signage to aid emergency responders.
This rulemaking was issued in “final-omitted” form. That action is taken in special cases when it is deemed necessary to respond to an emergency, and allows the Commonwealth to issue rules without publishing a proposed rule or offering them for public comment. Because Governor Corbett’s Marcellus Shale Advisory Commission had recommended that actions be taken to enhance emergency response at unconventional well sites and that the lack of effective emergency response has a direct and immediate impact on human health, safety, and welfare, the final-omitted rulemaking form was used to add sections to 25 Pa Code, Chapter 78 relating to oil and gas wells. The regulation was published in the January 26, 2013, Pennsylvania Bulletin and became effective on the same date, with the exceptions noted below.
Site address registration requirements of 25 Pa Code 78.55(f)(3) became effective on February 25, 2013. Since then and prior to construction of an access road to a well site, operators have been required to obtain a municipal street address for the site and determine GPS coordinates for both the well and site entrance. The site name, address, and GPS coordinates are to be registered with PEMA, the PADEP, the county emergency management organization, and the 9-1-1 Public Safety Answering Point (PSAP).
Emergency Response Plans
Emergency response plan requirements contained in 25 Pa Code 78.55(f)(5) took effect on April 26, 2013. Operators are required to have implemented “an emergency response plan that provides for equipment, procedures, training, and documentation to properly respond to emergencies that threaten human health and safety for each well site.” These plans are to “incorporate National Incident Management System planning standards, including the use of the Incident Command System, Incident Action Planning, and Common Communication Plans.” Six categories of emergency are to be addressed:
- Explosion or similar event;
- Security breach or other security event; and
- Any other incident that necessitates the presence of emergency responders.
Other key elements to be included in these plans include:
- Emergency contact information and notification procedures;
- Procedures to provide current hazardous material (e.g., MSDS) information to emergency responders;
- A list of fire suppression and spill control equipment;
- A description of off-site emergency equipment;
- A summary of risks to the public located within ½-mile of the site; and
- An outline of the emergency response training plan.
Provisions have been included for the preparation of a common base plan and then site-specific plans unique to each location. Plans are required to address each of the following stages of operation:
- Preparation of the access road and well site;
- Drilling the well;
- Hydraulic fracturing and stimulation of the well;
- Site restoration; and
- Plugging of the well.
In addition to being maintained at the site during all phases of operation, these plans are to be distributed to PEMA, the PADEP, the county emergency management agency, and the PSAP. The plan must be reviewed annually on or before March 1. If updates are required, they must be submitted to the same recipients. Otherwise a statement indicating that a review occurred but no updates were needed must be submitted.
The final element of these new requirements addresses signage. Signage requirements specified at 25 Pa Code 78.55(f)(4) take effect on July 25, 2013. Prior to constructing an access road, operators will be required to display a sign that meets specific fabrication, design, size, content, and installation requirements. “Sample Site Entrance Signage” is provided within the PA Bulletin link noted above.
PADEP acknowledges that industry will incur costs associated with preparing emergency response plans and posting signs but expects that “responsible operators already do both.” As such, the incremental costs are expected to be insignificant. To assist with the implementation of these requirements, PADEP intends to implement a compliance assistance plan with regional training sessions presented by PADEP and PEMA.
If you are unclear about how this regulation affects your operations or have questions regarding these requirements, please contact Kris Macoskey at 800-365-2324 or via email at firstname.lastname@example.org.
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 email@example.com.
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, firstname.lastname@example.org. You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.
You may be a bit confused about another deadline for Spill Prevention, Control and Countermeasure (SPCC) Plans considering the long history of this evolving regulation. EPA’s complete regulatory history can be found in their SPCC history, but here’s a chronology of the highlights:
- 1973: Original SPCC Rule published in Federal Register (12/11)
- 1991, 1993, & 1997: Proposed revisions
- 2002: Final “revised” SPCC Rule published (7/17)
- 2003 – 2006: Several compliance date extensions
- 2006: SPCC Rule Amendments (12/26)
- 2007 – 2009: Additional compliance date extensions
- 2009: Compliance Date Extended to November 10, 2010 (6/19)
- 2009: Final Rule on Amendments (11/5)
Three key take-aways from this history should be that 1) these regulations have been evolving for over 35 years now, 2) a final rule has been in place since 2002, and 3) the current compliance deadline is November 10, 2010.
Owner/operators should be aware that none of the regulatory actions that have occurred since 2002 have removed the obligation of affected facilities to comply with the Rule. EPA explains that compliance dates have been extended to allow owner/operators time to understand all the revisions and make changes as applicable to their facilities and plans. However, EPA states that “facilities must amend or prepare, and implement SPCC Plans by the compliance date in accordance with revisions to the SPCC rule promulgated since 2002.”
On November 5, 2009, the EPA Administrator signed the current “final” amendments to the SPCC Rule. The amendments are designed to increase clarity and streamline the requirements for SPCC Plans. The criteria for facilities to have and implement an SPCC Plan have not been changed. Non-transportation facilities with sufficient storage capacity that could discharge oil into navigable waters and/or shorelines are still subject to the Rule.
Tier I and II Facilities
The major recent change to the Rule is creation of Tier I and Tier II facilities. Tier I facilities are generally smaller sites with the following characteristics:
- Oil storage of less than 10,000 gallons aboveground;
- No single tank larger than 5,000 gallons; and
- No single oil discharge of more than 1,000 gallons in 3-year period, or no more than two discharges in excess of more than 42 gallons in any 12-month period.
SPCC Plans for Tier I facilities can be greatly simplified by using EPA’s template Tier I SPCC Plan. Tier I plans are not required to address many basic elements such as a facility diagram or facility description, compliance with facility drainage requirements or brittle fracture evaluations, and compliance with loading/unloading rack provisions. These plans may either be self-certified or certified by a Professional Engineer. The amendment does not supersede any state requirements for a Professional Engineer to certify the SPCC Plan.
Tier II facilities have the same characteristics as Tier I, except that the facility has at least one aboveground oil storage tank in excess of 5,000 gallons. Tier II facilities can be either self-certified or PE-certified, but they cannot use the template SPCC Plan.
November 10, 2010 Deadline
The significance of the November 10, 2010 compliance deadline depends on when the facility started operation, as follows:
|Date Facility Commenced Operation||November 10, 2010 Compliance Obligation|
|On or before August 16, 2002||Maintain the existing SPCC Plan and make amendments and implement changes as needed to comply with post-2002 revisions.|
|From August 16, 2002 through November 10, 2010||Prepare and implement an SPCC Plan consistent with current rules.|
|After November 10, 2010||Prepare and implement an SPCC Plan consistent with current rules before beginning operation.|
At this time, EPA’s recommends that facilities subject to the SPCC rule:
- Review the SPCC Rule, amendments, and compliance deadlines;
- Identify areas of your SPCC Plan that require amendment (if applicable);
- Make necessary facility modifications, if any; and
- Ensure that your SPCC Plan is up-to-date by November 10, 2010.
If you have any questions about SPCC applicability or recent amendments, please contact Kris Macoskey, QEP, at email@example.com or Paul Tomiczek, P.E., at firstname.lastname@example.org (800-365-2324). More information on EPA’s SPCC Rule can be found at EPA’s SPCC website: EPA’s SPCC Rule page.
As discussed in an earlier posting, Greenhouse Gas (GHG) reporting will be required for 24 source categories (in some cases dependent on emission levels) and facilities with stationary fuel combustion sources that meet specific criteria. Subpart C deals with the specific reporting, recordkeeping and verification requirements for GHG emissions from fuel combustion.
Starting in 2010, GHG emissions reporting will be required of facilities that have stationary fuel combustion sources where:
- The aggregate maximum rated heat input capacity of all units at facility exceeds 30 MMBtu/hr, and
- The facility has GHG emissions exceeding 25,000 metric tons (mt)/year
The regulations define a fuel combustion source as any device that combusts any of 55 solid, liquid or gaseous fuels and includes boilers, stationary internal combustion engines, process heaters, combustion turbines, incinerators, and various other types of equipment. The requirement addresses industrial, commercial and institutional (but not residential) uses of fuel in any combustion device with exemptions for the following:
- Portable equipment;
- Emergency generators/equipment;
- Irrigation pumps at agricultural operations;
- Flares, unless otherwise required by another subpart;
- Electricity generating units subject to Subpart D; and
- Hazardous waste combustion (unless a continuous emission monitoring system (CEMS) is used to monitor CO2 or the unit co-fires fossil fuels)
The fuel consumed as well as the annual operating hours will dictate whether reporting is required. The regulation provides equations for the calculation of GHG emissions based on the type of fuel, the default high heating value (HHV) of the fuel, and fuel-specific emission factors (EF). There are 4 “Tiers” of calculations based on the type of information available as summarized below:
- Tier 1 – use annual fuel consumption (from company records), fuel-specific HHV, and default CO2 emission factors;
- Tier 2 – use annual fuel consumption (from company records), measured fuel-specific HHV, and default CO2 emission factors;
- Tier 3 – use annual fuel consumption from company records (for solid fuels) or directly measured fuel consumption values (for liquid and gaseous fuels) and periodic fuel carbon content measurements; and
- Tier 4 – use CEMS data. There are a variety of restrictions on the use of the Tier 4 methodology. The rule should be consulted prior to using this method.
As an example, GHG emissions reporting will not be triggered unless fuel consumption exceeds the following:
|When Do You Need to Report?|
|Fuel||Design Capacity(MMBtu/hr)||Maximum Annual Fuel Use1|
|Coal||30||> 10,800 short tons|
|Fuel Oil||35||>2.3 million gallons|
|Natural Gas||50||>460 million ft3 (460,000 Therm)|
|Biogas (recovered methane)||50||>570 million ft3|
|Wood||30||> 10,600 short tons|
|Ethanol||40||> 4.3 million gallons|
1Approximate values assuming full utilization; 8,760 hours/year; and Tier 1 calculation
Regardless of the design capacity, emissions will remain below 25,000 mt/yr if the fuel consumption is below the maximum levels specified above. Similar calculations can be made for other fuel types based on the HHV and EF provided in Table C-1 of Subpart C.
Facilities with combustion units that are exempt from state air quality permitting requirements (e.g., in many states, those individually rated at less than 10 MMBtu/hr are exempt from permitting) will be subject to all of the GHG reporting and documentation requirements. For some facilities that had been tracking and reporting their GHG emissions on a voluntary basis (or due to state requirements), the new regulation may result in an increase in calculated GHG emissions due to the inclusion of GHG emissions from smaller (exempt) combustion units and/or changes in calculation methodology.
CEC recommends that facilities inventory all fuel combustion sources to evaluate whether this Subpart applies or if the facility is exempt from reporting. 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.
If you are following the new 40 CFR 98 Mandatory Greenhouse Gas Reporting Rule (GHG Rule) you will know that facilities were to have started collecting reporting data on January 1, 2010. You may be studying the requirements specific to your facility or industry group, but be sure to also take a careful look at Subpart A – General Provisions. Subpart A contains provisions that are applicable to all facilities subject to the GHG Rule requirements. A thorough understanding of Subpart A is a necessary prerequisite to complying with this new regulation. Key elements include:
- Who must report;
- When you can stop reporting;
- How and when reports must be submitted;
- What the annual report must contain;
- Special provisions that have been made for 2010 reporting;
- Recordkeeping requirements;
- Calibration requirements; and
- Definitions as well as tables of greenhouse gases (GHGs) and their global warming potentials.
The who, how, and when of reporting were addressed in our December 23, 2009 posting, but it is important to note that reporting is required on a facility-specific basis. A facility, as defined in Subpart A, can be limited to a single stationary piece of equipment that emits a GHG.
The criteria for determining when reporting can cease is a function of whether or not the facility continues to emit GHGs and at what levels. Continuous annual reporting is required unless:
- The facility has five consecutive years of emissions below 25,000 metric tons (mt);
- Three consecutive years of emissions below 15,000 mt; or
- All GHG-emitting processes and operations subject to the rule cease to operate (although this provision does not apply to MSW landfills).
At least 60 days prior to submitting the first annual report, an electronic certificate of representation must be submitted to EPA. EPA expects each facility to have only one designated representative who will be responsible for certifying, signing, and submitting GHG reports. The contents of the annual report will include:
- Facility name or supplier name and address;
- The period of time covered by the report;
- The date of the report;
- For facilities – annual emissions of GHG as follows:
- aggregate annual emissions (excluding biogenic CO2) for all GHG from all applicable source categories and expressed as carbon dioxide equivalents (CO2e);
- aggregate annual emissions of biogenic CO2e;
- individual GHG totals for each applicable source category; and
- other data as specified in the respective subparts.
- For suppliers – annual quantities of GHG that would be emitted from combustion or use of the supplied products during the year, as follows:
- aggregate annual emissions for all GHG from all applicable supply categories expressed as CO2e;
- individual GHG totals for each applicable supply category; and
- other data as specified in the respective subparts.
One special provision for the 2010 report is the allowance for best available monitoring methods. EPA expects GHG emissions to be estimated according to the specified methods. However, due to the limited notice provided prior to the effective date, if it was not reasonably feasible to acquire, install, and operate required monitoring equipment by January 1, 2010, then best available monitoring methods may be used until March 31, 2010. Best available methods may include:
- Monitoring methods currently used by the facility that do not meet the specification of the relevant subpart;
- Supplier data;
- Engineering calculations; and
- Other company records.
Extensions for continued use of best available monitoring methods beyond April 1, 2010 may be requested, but such requests need to be submitted by January 28, 2010.
Another special provision for the 2010 report applies to facilities where the only sources of CO2e are general stationary fuel combustion. For such facilities, a simplified report will be accepted. It would include the aggregate facility-wide GHG emissions and associated process information as well as general facility information and certification.
Records must be maintained for three years in either electronic or hard-copy format. Specific records that must be retained include:
- A list of all units, operations, processes, and activities for which GHG emissions were calculated;
- The data used to calculate GHG emissions including:
- emission calculations,
- analytical results for the development of site-specific emission factors,
- results of all required analyses (e.g., high heat value and carbon content), and
- any facility operating data or process information used in GHG calculations,
- Annual GHG reports;
- Missing data documentation;
- A written GHG Monitoring Plan;
- The results of all required certification and quality assurance (QA) tests of continuous monitoring systems, flow meters, and other instrumentation; and
- Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation.
The written GHG Monitoring Plan needs to identify who is responsible for collecting the data, what processes and methods are used to collect the data, and what procedures and methods are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other relevant instrumentation.
Relative to QA, EPA expects facilities to calibrate their flow meters and other measurement devices prior to April 1, 2010. Fuel billing meters are exempted from the requirement, but unless a device cannot be removed because of continuous operation, calibration in accordance with manufacturer recommendations is required. If a postponement in calibration is needed due to continuous operations, it must be documented in the GHG Monitoring Plan.
Other important elements of Subpart A include definitions that are applicable to the remaining subparts as well as Table A-1 that lists all 70 GHGs and their respective assigned global warming potentials.
CEC recommends that facilities develop a thorough GHG Monitoring Plan to document both the applicability determination as well as procedures that will be used to collect the required data, meet the QA requirements, and estimate emissions. In our next posting we will take an in-depth look at Subpart C – General Stationary Fuel Combustion Sources.
If you have any questions regarding the requirements of Subpart A or other portions of the GHG Rule, please contact one of CEC’s GHG experts, Kris Macoskey. Their contact information can be found on the CEC Experts page.