Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing a regulation to require reporting of greenhouse gas emissions from all sectors of the economy. The rule would apply to fossil fuel suppliers and industrial gas suppliers, as well as to direct greenhouse gas emitters. The proposed rule does not require control of greenhouse gases, rather it requires only that sources above certain threshold levels monitor and report emissions.
Comments must be received on or before June 9, 2009. There will be two public hearings. One hearing was held on April 6 and 7, 2009, in the Washington, DC, area (One Potomac Yard, 2777 S. Crystal Drive, Arlington, VA 22202). One hearing will be on April 16, 2009 in Sacramento, CA (Sacramento Convention Center, 1400 J Street, Sacramento, CA 95814). The April 16, 2009 hearing will begin at 9 a.m. local time.
Submit your comments, identified by Docket ID No. EPA–HQ–OAR–2008–0508, by one of the following methods:
• Federal eRulemaking Portal:
• E-mail:
• Fax: (202) 566–1741.
• Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mailcode 6102T, Attention Docket ID No. EPA–HQ–OAR–2008–0508, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
• Hand Delivery: EPA Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC 20004. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.
Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC–6207J), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 343–9263; fax number: (202) 343–2342; e-mail address:
Additional Information on Submitting Comments: To expedite review of your comments by Agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric Programs, Climate Change Division, Mail Code 6207–J, Washington, DC, 20460, telephone (202) 343–9263, e-mail
Regulated Entities. The Administrator determines that this action is subject to the provisions of CAA section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to “such other actions as the Administrator may determine.”). This is a proposed regulation. If finalized, these regulations would affect owners and operators of fuel and chemicals suppliers, direct emitters of GHGs and manufacturers of mobile sources and engines. Regulated categories and entities would include those listed in Table 1 of this preamble:
Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be regulated by this action. Table 1 of this preamble lists the types of facilities that EPA is now aware could be potentially affected by this action. Other types of facilities not listed in the table could also be subject to reporting requirements. To determine whether your facility is affected by this action, you should carefully examine the applicability criteria found in proposed 40 CFR part 98, subpart A. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding
Many facilities that would be affected by the proposed rule have GHG emissions from multiple source categories listed in Table 1 of this preamble. Table 2 of this preamble has been developed as a guide to help potential reporters subject to the mandatory reporting rule identify the source categories (by subpart) that they may need to (1) consider in their facility applicability determination, and (2) include in their reporting. For each source category, activity, or facility type (e.g., electricity generation, aluminum production), Table 2 of this preamble identifies the subparts that are likely to be relevant. The table should only be seen as a guide. Additional subparts may be relevant for a given reporter. Similarly, not all listed subparts would be relevant for all reporters.
The proposed rule would require reporting of annual emissions of carbon dioxide (CO
This preamble is broken into several large sections, as detailed above in the Table of Contents. Throughout the preamble we explicitly request comment on a variety of issues. The paragraph below describes the layout of the preamble and provides a brief summary of each section. We also highlight particular issues on which, as indicated later in the preamble, we would specifically be interested in receiving comments.
The first section of this preamble contains the basic background information about greenhouse gases and climate change. It also describes the origin of this proposal, our legal authority and how this proposal relates to other efforts to address emissions of greenhouse gases. In this section we
The second section of this preamble describes existing Federal, State, Regional mandatory and voluntary GHG reporting programs and how they are similar and different to this proposal. Again, similar to the previous section, we would like comments on the interrelationship of this proposal and existing GHG reporting programs.
The third section of this preamble provides an overview of the proposal itself, while the fourth section provides the rationale for each decision the Agency made in developing the proposal, including key design elements such as: (i) Source categories included, (ii) the level of reporting, (iii) applicability thresholds, (iv) reporting and monitoring methods, (v) verification, (vi) frequency and (vii) duration of reporting. Furthermore, in this section, EPA explains the distinction between upstream and downstream reporters, describes why it is necessary to collect data at multiple points, and provides information on how different data would be useful to inform different policies. As stated in the fourth section, we solicit comment on each design element of the proposal generally.
The fifth section of this preamble looks at the same key design elements for each of the source categories covered by the proposal. Thus, for example, there is a specific discussion regarding appropriate applicability thresholds, reporting and monitoring methodologies and reporting and recordkeeping requirements for each source category. Each source category describes the proposed options for each design element, as well as the other options considered. In addition to the general solicitation for comment on each design element generally and for each source category, throughout the fifth section there are specific issues highlighted on which we solicit comment. Please refer to the specific source category of interest for more details.
The sixth section of this preamble explains how EPA would collect, manage and disseminate the data, while the seventh section describes the approach to compliance and enforcement. In both sections the role of the States is discussed, as are requests for comment on that role.
Finally, the eighth section provides the summary of the impacts and costs from the Regulatory Impact Analysis and the last section walks through the various statutory and executive order requirements applicable to rulemakings.
The proposed rule would cover the major GHGs that are directly emitted by human activities. These include CO
Global atmospheric CO
Due to sheer quantity of emissions, CO
Because GHGs have different heat trapping capacities, they are not directly comparable without translating them into common units. The GWP, a metric that incorporates both the heat-trapping ability and atmospheric lifetime of each GHG, can be used to develop comparable numbers by adjusting all GHGs relative to the GWP of CO
For additional information about GHGs, climate change, climate science, etc. please see EPA's climate change Web site found at
Climate change refers to any significant changes in measures of climate (such as temperature, precipitation, or wind) lasting for an extended period. Historically, natural factors such as volcanic eruptions and changes in the amount of energy released from the sun have affected the earth's climate. Beginning in the late 18th century, human activities associated with the industrial revolution
According to the IPCC, warming of the climate system is “unequivocal,” as is now evident from observations of increases in global average air and ocean temperatures, widespread melting of snow and ice, and rising global average sea level. Global mean surface temperatures have risen by 0.74 °C (1.3 °F) over the last 100 years. Global mean surface temperature was higher during the last few decades of the 20th century than during any comparable period during the preceding four centuries. U.S. temperatures also warmed during the 20th and into the 21st century; temperatures are now approximately 0.56 °C (1.0 °F) warmer than at the start of the 20th century, with an increased rate of warming over the past 30 years. Most of the observed increase in global average temperatures since the mid-20th century is very likely due to the observed increase in anthropogenic GHG concentrations.
According to different scenarios assessed by the IPCC, average global temperature by end of this century is projected to increase by 1.8 to 4.0 °C (3.2 to 7.2 °F) compared to the average temperature in 1990. The uncertainty range of this estimate is 1.1 to 6.4 °C (2.0 to 11.5 °F). Future projections show that, for most scenarios assuming no additional GHG emission reduction policies, atmospheric concentrations of GHGs are expected to continue climbing for most if not all of the remainder of this century, with associated increases in average temperature. Overall risk to human health, society and the environment increases with increases in both the rate and magnitude of climate change.
For additional information about GHGs, climate change, climate science, etc. please see EPA's climate change Web site found at
On December 26, 2007, President Bush signed the FY2008 Consolidated Appropriations Act which authorized funding for EPA to “develop and publish a draft rule not later than 9 months after the date of enactment of this Act, and a final rule not later than 18 months after the date of enactment of this Act, to require mandatory reporting of GHG emissions above appropriate thresholds in all sectors of the economy of the United States.” Consolidated Appropriations Act, 2008, Public Law 110–161, 121 Stat 1844, 2128 (2008).
The accompanying joint explanatory statement directed EPA to “use its existing authority under the Clean Air Act” to develop a mandatory GHG reporting rule. “The Agency is further directed to include in its rule reporting of emissions resulting from upstream production and downstream sources, to the extent that the Administrator deems it appropriate.” EPA has interpreted that language to confirm that it may be appropriate for the Agency to exercise its CAA authority to require reporting of the quantity of fuel or chemical that is produced or imported from upstream sources such as fuel suppliers, as well as reporting of emissions from facilities (downstream sources) that directly emit GHGs from their processes or from fuel combustion, as appropriate. The joint explanatory statement further states that “[t]he Administrator shall determine appropriate thresholds of emissions above which reporting is required, and how frequently reports shall be submitted to EPA. The Administrator shall have discretion to use existing reporting requirements for electric generating units” under section 821 of the 1990 CAA Amendments.
EPA is proposing this rule under its existing CAA authority. EPA also proposes that the rule require the reporting of the GHG emissions resulting from the quantity of fossil fuel or industrial gas that is produced or imported from upstream sources such as fuel suppliers, as well as reporting of GHG emissions from facilities (downstream sources) that directly emit GHGs from their processes or from fuel combustion, as appropriate. This proposed rule would also establish appropriate thresholds and frequency for reporting.
Section 114(a)(1) of the CAA authorizes the Administrator to,
The scope of the persons potentially subject to a section 114(a)(1) information request (e.g., a person “who the Administrator believes may have information necessary for the purposes set forth in” section 114(a)) and the reach of the phrase “carrying out any provision” of the Act are quite broad. EPA's authority to request information reaches to a source not subject to the CAA, and may be used for purposes relevant to any provision of the Act. Thus, for example, utilizing sections 114 and 208, EPA could gather information relevant to carrying out provisions involving research (e.g., section 103(g)); evaluating and setting standards (e.g., section 111); and endangerment determinations contained in specific provisions of the Act (e.g., 202); as well as other programs.
Given the broad scope of sections 114 and 208 of the CAA, it is appropriate for EPA to gather the information required by this rule because such information is relevant to EPA's carrying out a wide variety of CAA provisions. For example, emissions from direct emitters should inform decisions about whether and how to use section 111 to establish NSPS for various source categories emitting GHGs, including whether there are any additional categories of sources that should be listed under section 111(b). Similarly, the information required of manufacturers of mobile
The
The U.S. submits the Inventory to the Secretariat of the UNFCCC as an annual reporting requirement. The UNFCCC treaty, ratified by the U.S. in 1992, sets an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. The U.S. has submitted the GHG inventory to the United Nations every year since 1993. The annual Inventory is consistent with national inventory data submitted by other UNFCCC Parties, and uses internationally accepted methods for its emission estimates.
In preparing the annual Inventory, EPA leads an interagency team that includes DOE, USDA, DOT, DOD, the State Department, and others. EPA collaborates with hundreds of experts representing more than a dozen Federal agencies, academic institutions, industry associations, consultants, and environmental organizations. The Inventory is peer-reviewed annually by domestic experts, undergoes a 30-day public comment period, and is also peer-reviewed annually by UNFCCC review teams.
The most recent GHG inventory submitted to the UNFCCC, the
The Inventory is a comprehensive top-down national assessment of national GHG emissions, and it uses top-down national energy data and other national statistics (e.g., on agriculture). To achieve the goal of comprehensive national emissions coverage for reporting under the UNFCCC, most GHG emissions in the report are calculated via activity data from national-level databases, statistics, and surveys. The use of the aggregated national data means that the national emissions estimates are not broken-down at the geographic or facility level. In contrast, this reporting rule focuses on bottom-up data and individual sources above appropriate thresholds. Although it would provide more specific data, it would not provide full coverage of total annual U.S. GHG emissions, as is required in the development of the Inventory in reporting to the UNFCCC.
The mandatory GHG reporting rule would help to improve the development of future national inventories for particular source categories or sectors by advancing the understanding of emission processes and monitoring methodologies. Facility, unit, and process level GHG emissions data for industrial sources would improve the accuracy of the Inventory by confirming the national statistics and emission estimation methodologies used to develop the top-down inventory. The results can indicate shortcomings in the national statistics and identify where adjustments may be needed.
Therefore, although the data collected under this rule would not replace the system in place to produce the comprehensive annual national Inventory, it can serve as a useful tool to better improve the accuracy of future national-level inventories.
At the same time, EPA solicits comment on whether the submission of the Inventory to the UNFCCC could be utilized to satisfy the requirements of the rule promulgated by EPA pursuant to the FY2008 Consolidated Appropriations Act.
For more information about the Inventory, please refer to the following Web site:
The proposed mandatory GHG reporting program would provide EPA, other government agencies, and outside stakeholders with economy-wide data on facility-level (and in some cases corporate-level) GHG emissions. Accurate and timely information on GHG emissions is essential for informing some future climate change policy decisions. Although additional data collection (e.g., for other source categories such as indirect emissions or offsets) may be required as the development of climate policies evolves, the data collected in this rule would provide useful information for a variety of policies. For example, through data collected under this rule, EPA would gain a better understanding of the relative emissions of specific industries, and the distribution of emissions from individual facilities within those industries. The facility-specific data would also improve our understanding of the factors that influence GHG emission rates and actions that facilities are already taking to reduce emissions. In addition, the data collected on some source categories such as landfills and manure management, which can be covered by the CAA, could also potentially help inform offset program design by providing fundamental data on current baseline emissions for these categories.
Through this rulemaking, EPA would be able to track the trend of emissions from industries and facilities within
The goal is to have this GHG reporting program supplement and complement, rather than duplicate, U.S. government and other GHG programs (
As discussed in Section II of this preamble, a number of EPA voluntary partnership programs include a GHG emissions and/or reductions reporting component (e.g., Climate Leaders, the Natural Gas STAR program). Because this mandatory reporting program would have much broader coverage than the voluntary programs, it would help EPA learn more about emissions from facilities not currently included in these programs and broaden coverage of these industries.
Also discussed in Section II of this preamble, DOE EIA implements a voluntary GHG registry under section 1605(b) of the Energy Policy Act. Under EIA's “1605(b) program,” reporters can choose to prepare an entity-wide GHG inventory and identify specific GHG reductions made by the entity.
Again, in Section II, existing State and Regional GHG reporting and reduction programs are summarized. Many of those programs may be broader in scope and more aggressive in implementation. States collecting that additional information may have determined that types of data not collected by this proposal are necessary to implement a variety of climate efforts. While EPA's proposal was specifically developed in response to the Appropriations Act, we also acknowledge, similar to the States, there may be a need to collect additional data from sources subject to this rule as well as other sources depending on the types of policies the Agency is developing and implementing (
On July 30, 2008, EPA published an ANPR on “Regulating Greenhouse Gas Emissions under the Clean Air Act” (73 FR 44354). The ANPR presented information relevant to, and solicited public comment on, issues regarding the potential regulation of GHGs under the CAA, including EPA's response to the U.S. Supreme Court's decision in
In response to the FY2008 Consolidated Appropriations Amendment, EPA has developed this proposed rulemaking. The components of this development are explained in the following subsections.
The mandatory reporting program would provide comprehensive and accurate data which would inform future climate change policies. Potential future climate policies include research and development initiatives, economic incentives, new or expanded voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap-and-trade program. Because we do not know at this time the specific policies that may be adopted, the data reported through the mandatory reporting system should be of sufficient quality to support a range of approaches. Also, consistent with the Appropriations Act, the reporting rule proposes to cover a broad range of sectors of the economy.
To these ends, we identified the following goals of the mandatory reporting system:
• Obtain data that is of sufficient quality that it can be used to support a range of future climate change policies and regulations.
• Balance the rule coverage to maximize the amount of emissions reported while excluding small emitters.
• Create reporting requirements that are consistent with existing GHG reporting programs by using existing GHG emission estimation and reporting methodologies to reduce reporting burden, where feasible.
In order to ensure a comprehensive consideration of GHG emissions, EPA organized the development of the proposal around seven categories of processes that emit GHGs: Downstream sources of emissions: (1) Fossil Fuel Combustion: Stationary, (2) Fossil Fuel Combustion: Mobile, (3) Industrial Processes, (4) Fossil Fuel Fugitive
For each category, EPA evaluated the requirements of existing GHG reporting programs, obtained input from stakeholders, analyzed reporting options, and developed the general reporting requirements and specific requirements for each of the GHG emitting processes.
A number of State and regional GHG reporting systems currently are in place or under development. EPA's goal is to develop a reporting rule that, to the extent possible and appropriate, would rely on similar protocols and formats of the existing programs and, therefore, reduce the burden of reporting for all parties involved. Therefore, each of the work groups performed a comprehensive review of existing voluntary and mandatory GHG reporting programs, as well as guidance documents for quantifying GHG emissions from specific sources. These GHG reporting programs and guidance documents included the following:
• International programs, including the IPCC, the EU Emissions Trading System, and the Environment Canada reporting rule;
• U.S. national programs, such as the U.S. GHG inventory, the ARP, voluntary GHG partnership programs (
• State and regional GHG reporting programs, such as TCR, RGGI, and programs in California, New Mexico, and New Jersey;
• Reporting protocols developed by nongovernmental organizations, such as WRI/WBCSD; and
• Programs from industrial trade organizations, such as the American Petroleum Institute's Compendium of GHG Estimation Methodologies for the Oil and Gas Industry and the Cement Sustainability Initiative's CO
In reviewing these programs, we analyzed the sectors covered, thresholds for reporting, approach to indirect emissions reporting, the monitoring or emission estimating methods used, the measures to assure the quality of the reported data, the point of monitoring, data input needs, and information required to be reported and/or retained. We analyzed these provisions for suitability to a mandatory, Federal GHG reporting program, and compiled the information. The full review of existing GHG reporting programs and guidance may be found in the docket at EPA–HQ–OAR–2008–0508–054. Section II of this preamble summarizes the fundamental elements of these programs.
Early in the development process, we conducted a proactive communications outreach program to inform the public about the rule development effort. We solicited input and maintained an open door policy for those interested in discussing the rulemaking. Since January 2008, EPA staff held more than 100 meetings with over 250 stakeholders. These stakeholders included:
• Trade associations and firms in potentially affected industries/sectors;
• State, local, and Tribal environmental control agencies and regional air quality planning organizations;
• State and regional organizations already involved in GHG emissions reporting, such as TCR, CARB, and WCI;
• Environmental groups and other nongovernmental organizations.
• We also met with DOE and USDA which have programs relevant to GHG emissions.
During the meetings, we shared information about the statutory requirements and timetable for developing a rule. Stakeholders were encouraged to provide input on key issues. Examples of topics discussed were, existing GHG monitoring and reporting programs and lessons learned, thresholds for reporting, schedule for reporting, scope of reporting, handling of confidential data, data verification, and the role of States in administering the program. As needed, the technical work groups followed up with these stakeholder groups on a variety of methodological, technical, and policy issues. EPA staff also provided information to Tribes through conference calls with different Indian working groups and organizations at EPA and through individual calls with Tribal board members of TCR.
For a full list of organizations EPA met with during development of this proposal, see the memo found at EPA–HQ–OAR–2008–0508–055.
A number of voluntary and mandatory GHG programs already exist or are being developed at the State, Regional, and Federal levels. These programs have different scopes and purposes. Many focus on GHG emission reduction, whereas others are purely reporting programs. In addition to the GHG programs, other Federal emission reporting programs and emission inventories are relevant to the proposed GHG reporting rule. Several of these programs are summarized in this section.
In developing the proposed rule, we carefully reviewed the existing reporting programs, particularly with respect to emissions sources covered, thresholds, monitoring methods, frequency of reporting and verification. States may have, or intend to develop, reporting programs that are broader in scope or are more aggressive in implementation because those programs are either components of established reduction programs (e.g., cap and trade) or being used to design and inform specific complementary measures (e.g., energy efficiency). EPA has benefitted from the leadership the States have shown in developing these programs and their experiences. Discussions with States that have already implemented programs have been especially instructive. Where possible, we built upon concepts in existing Federal and State programs in developing the mandatory GHG reporting rule.
EPA and other Federal agencies operate a number of voluntary GHG reporting and reduction programs that EPA reviewed when developing this proposal, including Climate Leaders, several Non-CO
There are two sector specific partnerships to reduce SF
At the same time, aspects of the voluntary programs serve as useful starting points for the mandatory GHG reporting rules. GHG emission calculation principles and protocols have been developed for various types of emission sources by Climate Leaders, the DOE 1605(b) program, and some partnerships such as the SF
The joint explanatory statement accompanying the FY2008 Consolidated Appropriations Amendment specified that EPA could use the existing reporting requirements for electric generating units under section 821 of the 1990 CAA Amendments.
A number of States have demonstrated leadership and developed corporate voluntary GHG reporting programs individually or joined with other States to develop GHG reporting programs as part of their approaches to addressing GHG emissions. EPA has
Several individual States and regional groups of States have demonstrated leadership and are developing or have developed mandatory GHG reporting programs and GHG emissions control programs. This section of the preamble summarizes two regional cap-and-trade programs and several State mandatory reporting rules. We recognize that, like the current voluntary regional and State programs, State and regional mandatory reporting programs may evolve or develop to include additional monitoring and reporting requirements than those included in the proposed rule. In fact, these programs may be broader in scope or more aggressive in implementation because the programs are either components of established reduction programs (e.g., cap and trade) or being used to design and inform specific complementary measures (e.g., energy efficiency).
A key difference between the Federal mandatory GHG reporting rule and the RGGI and WCI programs is that the Federal mandatory GHG rule is solely a reporting requirement. It does not in any way regulate GHG emissions or require any emissions reductions.
State rules differ with regard to which facilities must report and which GHGs must be reported. Some States require all facilities that must obtain Title V permits to report GHG emissions. Others require reporting for particular sectors (e.g., large EGUs, cement plants, refineries). Some State rules apply to any facility with stationary combustion sources that emit a threshold level of CO
The level of specificity regarding GHG monitoring and calculation methods varies. Some of the States refer to use of protocols established by TCR or CCAR. Others look to industry-specific protocols (such as methods developed by the American Petroleum Institute), to accepted international methodologies such as IPCC, and/or to emission factors in EPA's Compilation of Air Pollutant
The various existing State and Federal programs EPA reviewed are diverse. They apply to different industries, have different thresholds, require different pollutants and different types of emissions sources to be reported, rely on different monitoring protocols, and require different types of data to be reported, depending on the purposes of each program. None of the existing programs require nationwide, mandatory GHG reporting by facilities in a large number of sectors, so EPA's proposed mandatory GHG rule development effort is unique in this regard.
Although the mandatory GHG rule is unique, EPA carefully considered other Federal and State programs during development of the proposed rule. Documentation of our review of GHG monitoring protocols for each source category used by Federal, State, and international voluntary and mandatory GHG programs, and our review of State mandatory GHG rules can be found at EPA–HQ–OAR–2008–0508–056. The proposed monitoring and GHG calculation methodologies for many source categories are the same as, or similar to, the methodologies contained in State reporting programs such as TCR, CCAR, and State mandatory GHG reporting rules and similar to methodologies developed by EPA voluntary programs such as Climate Leaders. The reporting requirements set forth in 40 CFR part 75 are also being used for this proposed rule. Similarity in proposed methods would help maximize the ability of individual reporters to submit the emissions calculations to multiple programs, if desired. EPA also continues to work closely with States and State-based groups to ensure that the data management approach in this proposal would lead to efficient submission of data to multiple programs. Section V of this preamble includes further information on the selection of monitoring methods for each source category.
The intent of this proposed rule is to collect accurate and consistent GHG emissions data that can be used to inform future decisions. One goal in developing the rule is to utilize and be consistent with the GHG protocols and requirements of other State and Federal programs, where appropriate, to make use of existing cooperative efforts and reduce the burden to facilities submitting reports to other programs. However, we also need to be sure the mandatory reporting rule collects facility-specific data of sufficient quality to achieve the Agency's objectives for this rule. Therefore, some reporting requirements of this proposed rule are different from the State programs. The remaining sections of this preamble further describe the proposed rule requirements and EPA's rationale for all of the requirements.
EPA seeks comment on whether the conclusions drawn during its review of existing programs are accurate and invites data to demonstrate if, and if so how, the goals and objectives of this proposed mandatory reporting system could be met through existing programs. In particular, comments should address how existing programs meet the breadth of sources reporting, thresholds for reporting, consistency and stringency of methods for reporting, level of reporting, frequency of reporting and verification of reports included in this proposal.
The proposed rule would require reporting of annual emissions of CO
Owners and operators of the following facilities and supply operations would submit annual GHG emission reports under the proposal:
Facilities and suppliers would begin collecting data on January 1, 2010. The first emissions report would be due on March 31, 2011, for emissions during 2010.
The report would include total annual GHG emissions in metric tons of CO
Within a given source category, the report also would break out emissions at the level required by the respective subpart (e.g., reporting could be
In addition to GHG emissions, you would report certain activity data (e.g., fuel use, feedstock inputs) that were used to generate the emissions data. The required activity data are specified in each subpart. For some source categories, additional data would be reported to support QA/QC and verification.
EPA would protect any information claimed as CBI in accordance with regulations in 40 CFR part 2, subpart B. However, note that in general, emission data collected under CAA sections 114 and 208 cannot be considered CBI.
The reports would be submitted electronically, in a format to be specified by the Administrator after publication of the final rule.
Each report would contain a signed certification by a Designated Representative of the facility. On behalf of the owner or operator, the Designated Representative would certify under penalty of law that the report has been prepared in accordance with the requirements of 40 CFR part 98 and that the information contained in the report is true and accurate, based on a reasonable inquiry of individuals responsible for obtaining the information.
Each facility or supplier would also have to retain and make available to EPA upon request the following records for five years in an electronic or hard-copy format as appropriate:
• A list of all units, operations, processes and activities for which GHG emissions are calculated;
• The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type;
• Documentation of the process used to collect the necessary data for the GHG emissions calculations;
• The GHG emissions calculations and methods used;
• All emission factors used for the GHG emissions calculations;
• Any facility operating data or process information used for the GHG emissions calculations;
• Names and documentation of key facility personnel involved in calculating and reporting the GHG emissions;
• The annual GHG emissions reports;
• A log book documenting any procedural changes to the GHG emissions accounting methods and any changes to the instrumentation critical to GHG emissions calculations;
• Missing data computations;
• A written QAPP;
• Any other data specified in any applicable subpart of proposed 40 CFR part 98. Examples of such data could include the results of sampling and analysis procedures required by the subparts (e.g., fuel heat content, carbon content of raw materials, and flow rate) and other data used to calculate emissions.
This section of the preamble explains the rationales for EPA's proposals for various aspects of the rule. This section applies to all of the source categories in the preamble (further discussed in Sections V.B through V.PP of this preamble) with the exception of mobile sources (discussed in Section V.QQ of this preamble). The proposals EPA is making with regard to mobile sources are extensions of existing EPA programs and therefore the rationales and decisions are discussed wholly within that section. With respect to the source categories B through PP, EPA is particularly interested in receiving comments on the following issues:
(1) Reporting thresholds. EPA is interested in receiving data and analyses on thresholds. In particular, we solicit comment on whether the thresholds proposed are appropriate for each source category or whether other emissions or capacity based thresholds should be applied. If suggesting alternative thresholds, please discuss whether and how they would achieve broad emissions coverage and result in a reasonable number of reporters.
(2) Methodologies. EPA is interested in receiving data, technical information and analyses relevant to the methodology approach. We solicit comment on whether the methodologies selected by EPA are appropriate for each source category or whether alternative approaches should be adopted. In particular, EPA would like information on the technical feasibility, costs, and relative improvement in accuracy of direct measurement at facilities. If suggesting an alternative methodology (e.g., using established industry default factors or allowing industry groups to propose an industry specific emission factor to EPA), please discuss whether and how it provides complete and accurate emissions data, comparable to other source categories, and also reflects broadly agreed upon calculation procedures for that source category.
(3) Frequency and year of reporting. EPA is interested in receiving data and analyses regarding frequency of reporting and the schedule for reporting. In particular, we solicit information regarding whether the frequency of data collection and reporting selected by EPA is appropriate for each source category or whether alternative frequencies should be considered (e.g., quarterly or every few years). If suggesting an alternative frequency, please discuss whether and how it ensures that EPA and the public receive the data in a timely fashion that allow it to be relevant for future policy decisions. EPA is proposing 2010 data collection and 2011 reporting, however, we are interested in receiving comment on alternative schedules if we are unable to meet our goal.
(4) Verification. EPA is interested in receiving data and analyses regarding verification options. We solicit input on whether the verification approach selected by EPA is appropriate for each source category or whether an alternative approach should be adopted. If suggesting an alternative verification approach, please discuss how it weighs the costs and burden to the reporter and EPA as well as the need to ensure the data are complete, accurate, and available in the timely fashion.
(5) Duration of the program. EPA is interested in receiving data and analyses regarding options for the duration of the GHG emissions information collection program in this proposed rule. By duration, EPA means for how many years the program should require the submission of information. EPA solicits input on whether the duration selected by EPA is appropriate for each source category or whether an alternative approach should be adopted. If suggesting an alternative duration, please discuss how it impacts the need to ensure the data are sufficient to inform the variety of potential policy decisions regarding climate change under consideration.
The proposed rule would require reporting of CO
The IPCC focuses on CO
There are other GHGs and aerosols that have climatic warming effects that we are not proposing to include in this rule: Water vapor, CFCs, HCFCs, halons, tropospheric O
Section III of this preamble lists the source categories that would submit reports under the proposed rule. The source categories identified in this list were selected after considering the language of the Appropriations Act and the accompanying explanatory statement, and EPA's experience in developing the U.S. GHG Inventory. The Appropriations Act referred to reporting “in all sectors of the economy” and the explanatory statement directed EPA to include “emissions from upstream production and downstream sources to the extent the Administrator deems it appropriate.”
As a starting point, EPA first considered all anthropogenic sources of GHG emissions. The term “anthropogenic” refers to emissions that are produced as a result of human activities (e.g., combustion of coal in an electric utility or CH
As a second step, EPA considered all of the source categories in the
As a third step, EPA also carefully reviewed the recently completed 2006 IPCC Guidelines for National Greenhouse Gas Inventories for additional source categories that may be relevant for the U.S. These international guidelines are just beginning to be incorporated into national inventories. The 2006 IPCC Guidelines identified one additional source category for consideration (fugitive emissions from fluorinated GHG production).
As a fourth step, once EPA had a complete list of source categories relevant to the U.S., the Agency systematically reviewed those source categories against the following criteria to develop the list to the source categories included in the proposal:
(1) Include source categories that emit the most significant amounts of GHG emissions, while also minimizing the number of reporters, and
(2) Include source categories that can be measured with an appropriate level of accuracy.
To accomplish the first criterion, EPA set reporting thresholds, as described in Section IV.C of this preamble, that are designed to target large emitters. When the proposed thresholds are applied, the source categories included in this proposal meet the criterion of balancing the emissions coverage with a reasonable number of reporters. For more detailed information about the coverage of emissions and number of reporters see the Thresholds TSD (EPA–HQ–OAR–2008–0508–046) and the RIA (EPA–HQ–OAR–2008–0508–002).
The second criterion was to require reporting for only those sources for which measurement capabilities are sufficiently accurate and consistent. Under this criterion, EPA considered whether or not facility reporting would be as effective as other means of obtaining emissions data. For some sources, our understanding of emissions is limited by lack of knowledge of source-specific factors. In instances where facility-specific calculations are feasible and result in sufficiently accurate and consistent estimates, facility-level reporting would improve current inventory estimates and EPA's understanding of the types and levels of emissions coming from large facilities, particularly in the industrial sector. These source categories have been included in the proposal. For other source categories, uncertainty about emissions is related more to the unavailability of emission factors or simple models to estimate emissions accurately and at a reasonable cost at the facility-level. Under this criterion, we would require facility-level reporting only if reporting would provide more accurate estimates than can be obtained by other means, such as national or regional-level modeling. For an example, please refer to the discussion below on emissions from agricultural sources and other land uses.
As the Agency completed its four step evaluation of source categories to include in the proposal, some source categories were excluded from consideration and some were added. The reasons for the additions and deletions are explained below. In general, the proposed reporting rule covers almost all of the source categories in the
For more information about the thresholds included in this proposal please refer to Section IV.C of this
There is inherent double-reporting of emissions in a program that includes both upstream and downstream sources. For example, coal mines would report CO
It is possible to construct a reporting system with no double-reporting. For example, such a system could include fossil fuel combustion-related emissions upstream only, based on the fuel suppliers, supplemented by emissions reported downstream for industrial processes at select industries (e.g., CO
EPA reports on the GHG emissions and sinks associated with agricultural and land-use sources in the
The challenges to including these direct emission source categories in the rule are that practical reporting methods to estimate facility-level emissions for these sources can be difficult to implement and can yield uncertain results. For more information on uncertainty for these sources, please refer to the TSD for Biological Process Sources Excluded from this Rule (EPA–HQ–OAR–2008–0508–045). Furthermore, these sources are characterized by a large number of small emitters. In light of these challenges, we have determined that it is impractical to require reporting of emissions from these sources in the proposed rule at
For these sources, currently, there are no direct greenhouse gas emission measurement methods available except for research methods that are prohibitively expensive and require sophisticated equipment. Instead, limited modeling-based methods have been developed for voluntary GHG reporting protocols which use general emission factors, and large-scale models have been developed to produce comprehensive national-level emissions estimates, such as those reported in the U.S. GHG inventory report.
To calculate emissions using emission factor or carbon stock change approaches, it would be necessary for landowners to report on management practices, and a variety of data inputs. Activity data collection and emission factor development necessary for emissions calculations at the scale of individual reporters can be complex and costly.
For example, for calculating emissions of N
Without reasonably accurate facility-level emissions factors and the ability to accurately measure all facility-level calculation variables at a reasonable cost to reporters, facility-level emissions reporting would not improve our knowledge of GHG emissions relative to national or regional-level emissions models and data available from national databases. While a systematic measurement program of these sources could improve understanding of the environmental factors and management practices that influence emissions, this type of measurement program is technically difficult and expensive to implement, and would be better accomplished through an empirical research program that establishes and maintains rigorous measurements over time.
Despite the issues associated with reporting by the agriculture and land use sectors, threshold analyses were conducted for several source categories within these sectors as part of their consideration for inclusion in this rule. For some agricultural source categories, the number of individual farms covered at various thresholds was estimated. The resulting analyses showed that for most of these sources no facilities would exceed any of the thresholds evaluated.
Because facility-level reporting is impracticable, the proposed rule contains other provisions to improve our understanding of emissions from these source categories. For example, agricultural soil management is a significant source of N
EPA is requesting comment on this approach. In particular, the Agency is looking for information on the usefulness of the fertilizer data for estimating N
For additional background information on emissions from agricultural sources and other land use, please refer to the TSD for Biological Process Sources Excluded from this Rule (EPA–HQ–OAR–2008–0508–045).
The proposed rule would establish reporting thresholds at the facility level.
The thresholds are expressed in several ways (e.g., actual emissions or capacity). The use of these different types of thresholds is discussed later in this section, but most correspond to an annual facility-wide emission level of 25,000 metric tons of CO
The lower threshold alternatives that we considered were 1,000 metric tons of CO
A 1,000 metric ton of CO
A 10,000 metric ton of CO
We also considered 100,000 metric tons of CO
The data collected by this rulemaking is intended to support analyses of future policy options. Those options may depend on harmonization with State or even international reporting programs. Several States and regional GHG programs are using thresholds that are comparable in scope to a 25,000 metric ton of CO
In addition to the typical emissions thresholds associated with GHG reporting and reduction programs (e.g., 25,000 metric tons CO
EPA performed some preliminary analyses to generally estimate the existing stock of major sources in order to then estimate the approximate number of new facilities that could be required to obtain NSR/PSD permits.
For more information about the affect of thresholds considered for this rule on the number of reporters, emissions coverage and costs, please see Table VIII–2 in Section VIII of this preamble and Table IV–47 of the RIA found at EPA–HQ–OAR–2008–0508–002.
EPA carefully examined thresholds and source categories that might be able
The scope of the proposed emission threshold is emissions from all applicable source categories located within the physical boundary of a facility. To determine emissions to compare to the threshold, a facility that directly emits GHGs would estimate total emissions from all source categories for which emission estimation methods are provided in proposed 40 CFR part 98, subparts C through JJ. The use of total emissions is necessary because some facilities are comprised of multiple process units or collocated source categories that individually may not be large emitters, but that emit significant levels of GHGs collectively. The calculation of total emissions for the purposes of determining whether a facility exceeds the threshold should not include biogenic CO
In order to ensure that the reporting of GHG emissions from all source categories within a facility's boundaries is not unduly burdensome, EPA has proposed flexibility in two ways. First, a facility would only have to report on the source categories for which there are methods provided in this rule. EPA has proposed methods only for source categories that typically contribute a relatively significant amount to a facility's total GHG emissions (e.g., EPA has not provided a method for a facility to account for the CH
The proposed emissions threshold is based on actual emissions, with a few exceptions described below. An actual emission metric accounts for actual operating practices at each facility. A threshold based on potential emissions would bring in far more facilities including many small emitters. For example, under a potential emissions threshold, a facility that operates one shift a day would have to estimate emissions assuming three shifts per day, and would have to assume continuous use of feedstocks or fuels that result in the highest rate of GHG emissions absent enforceable limitations. Such an approach would be inconsistent with the twin goals of collecting accurate data on actual GHG emissions to the atmosphere and excluding small emitters from the rule. However, we note that emissions thresholds in some CAA rules are based on actual or potential emissions. Moreover, although actual emissions may change year to year due to fluctuations in the market and other factors, potential emissions are less subject to yearly fluctuations. We solicit comment on how considerations of actual and potential emissions should be incorporated into the proposed threshold.
There is one source category that has a proposed threshold based on GHG generation instead of emissions—municipal landfills. In this case, a GHG generation threshold is more appropriate because some landfills have installed CH
As described in Section III of this preamble, in the case of 19 source categories all of the facilities that have that particular source category within their boundaries would be subject to the proposed rule. For these facilities, our analysis indicated that all facilities with that source category emit more than 25,000 metric tons of CO
When determining if a facility passes a relevant applicability threshold, direct emissions from the source categories would be assessed separately from the emissions from the supplier categories. For example, a company that produces and supplies coal would be subject to reporting as a supplier of coal (40 CFR part 98, subpart KK), because coal suppliers is an “all in” supplier category. But the company would separately evaluate whether or not emissions from their underground coal mines (40 CFR part 98, subpart FF) would also be reported.
In addition, the source categories listed in proposed 40 CFR 98.2(a)(1) and (2) and the supply operations listed in proposed 40 CFR 98.2(a)(4) represent EPA's best estimate of the large emitters of GHGs or large suppliers of fuel and industrial GHGs. In order to ensure that all large emitters are included in this reporting program, proposed 40 CFR 98.2(a)(3) also covers any facility that emits more than 25,000 metric tons of CO
Furthermore, we recognize that a potentially large number of facilities would need to calculate their emissions in order to determine whether or not they had to report under proposed 40 CFR 98.2(a)(3). Therefore, to further minimize the burden on those facilities, we are proposing that any facility that has an aggregate maximum rated heat input capacity of the stationary fuel combustion units less than 30 mmBtu/hr may presume it has emissions below the threshold. According to our analysis, a facility with stationary combustion units that have a maximum rated heat input capacity of less that 30 mmBtu/hr, operating full time (e.g., 8,760 hours per year) with all types of fossil fuel would not exceed 25,000 metric tons CO
We are proposing that once a facility is subject to this reporting rule, it would continue to submit annual reports even if it falls below the reporting thresholds in future years. (As discussed in section IV.K. of this preamble, EPA is proposing that this rule require the submission of data into the foreseeable future, although EPA is soliciting comment on other options.) The purpose of the thresholds is to exclude small sources from reporting. For sources that trigger the thresholds, it is important for the purpose of policy analysis to be able to track trends in emissions and understand factors that influence emission levels. The data would be most useful if the population of reporting sources is consistent, complete and not varying over time.
The one exception to the proposed requirement to continue submitting reports even if a facility falls below the reporting threshold is active underground coal mines. When coal is no longer produced at a mine, the mine often becomes abandoned. As discussed in Section V.FF of this preamble, we are proposing to exclude abandoned coal mines from the proposed rule, and therefore methods are not proposed for this source category.
We recognize that in some cases, this provision of “once in, always in” could potentially act as a disincentive for some facilities to reduce their emissions because under this proposal those facilities that did lower their emissions below the treshold would have to continue to report. To address this issue in California, CARB's mandatory reporting rule offers a facility that has emissions under the threshold for three consecutive years the opportunity to be exempt from the reporting program. We request comment on whether EPA should develop a similar process for this reporting program. Comments should include specifics on how the exemption process could work, e.g., the number of years a facility is under the threshold before they could be exempt, the quantity of emissions reductions required before a facility could be exempt, whether a facility should formally apply to EPA for an exemption or if it is automatic, etc.
EPA requests comment on the need for developing simplified emissions calculation tools for certain source categories to assist potential reporters in determining applicability. These simplified calculation tools would provide conservatively high emission estimates as an aid in identifying facilities that could be subject to the rule. Actual facility applicability would be determined using the methods presented for each source category in the rule.
For additional information about the threshold analysis EPA conducted see the Thresholds TSD (EPA–HQ–OAR–2008–0508–046) and the individual source category discussions in Section V of this preamble. In addition, Section V.QQ of this preamble describes the threshold for vehicle and engine manufacturers, which is a different approach from what is described in this section.
EPA is proposing facility-level reporting for most source categories under this program. Specifically, the owner or operator of a facility would be required to report its GHG emissions from all source categories for which there are methods developed and listed in this proposal. For example, a petroleum refinery would have to report its emissions resulting from stationary combustion, production processes, and any fugitive or biological emissions. Facility-level reporting by owners or operators is consistent with other CAA or State-level regulatory programs that typically require facility or unit level data and compliance (e.g., ARP, NSPS, RGGI, and the California and New Mexico mandatory GHG reporting rules). This approach allows flexibility for firms to determine whether the owner or operator of the facility would report and avoid the challenges of establishing complex reporting rules based on equity or operational control.
In addition to reporting emissions at the total facility level, the emissions would also be broken out by source category (e.g., a petroleum refinery would separately identify its emissions for refinery production processes, wastewater, onsite landfills, and any other source categories listed in proposed 40 CFR part 98, subpart A that are located onsite). This would enable EPA to understand what types of emission sources are being reported, determine that the facility is reporting for all required source categories, and use the source-category specific estimates for future policy development. Within each source category, further breakout of emissions by process or unit may be specified. Information on process or unit-level reporting and associated rationale is contained in the source category sections within Section V of this preamble.
Although many voluntary programs such as Climate Leaders or TCR have corporate-level reporting systems, EPA concluded that corporate-level reporting is overly complex under a mandatory system involving many reporters and thus is not appropriate for this rule, except where discussed below. Complex ownership structures and the frequent changes in ownership structure make it difficult to establish accountability over time and ensure consistent and uniform data collection at the facility-level. Because the best technical knowledge of emitting processes and emission levels exists at the facility level, this is where responsibility for reporting should be placed. Furthermore, the ability to differentiate and track the level and type of emissions by facility, unit or process, is essential for development of certain types of future policy (e.g., NSPS).
The only exception to facility level reporting is for some supplier source categories (e.g., importers of fuels and industrial GHGs or manufacturers of motor vehicles and engines). Importers are not individual facilities in the traditional sense of the word. The type of information reported by motor vehicle and engine manufacturers is an extension of long-standing existing reporting requirements (e.g., reporting of criteria emissions rates from vehicle and engine manufacturers) and as such does not necessitate a change in reporting level. The reporting level for these source categories is specified in Section V of this preamble.
EPA is proposing that the monitoring and reporting requirements would start on January 1, 2010.
For existing facilities that meet the applicability criteria in proposed 40 CFR part 98, subpart A, monitoring would begin on January 1, 2010. For new facilities that begin operation after January 1, 2010, monitoring would begin with the first month that the facility is operating and end on December 31 of that same calendar year in which they start operating. Each subsequent monitoring year would begin on January 1 and end on December 31 of each calendar year. EPA is proposing that new facilities monitor and report emissions for the first partial year after they begin operating so that EPA has as complete an inventory as possible of GHG emissions for each calendar year.
Due to the comprehensive reporting and monitoring requirements in this proposal, the Agency has concluded that it is not appropriate to require reporting of historical emissions data for years before 2010. Compiling, submitting, and verifying historical data according to the methodologies specified in this rule would create additional burdens on both the affected facilities and the Agency, and much of the needed data might not be available. Because Federal policy for GHG emissions is still being developed, the Agency's focus is on collecting data of known quality that is generated on a consistent basis. Collecting historic emissions data would introduce data of unknown quality that would not be comparable to the data reported under the program for years 2011 and beyond.
The first year of monitoring for existing facilities would begin on January 1, 2010. This schedule would give existing facilities lead time after the date the rule is promulgated to prepare for monitoring and reporting. Preparation would include studying the final rule, determining whether it applies to the facility, identifying the requirements with which the facility must comply, and preparing to monitor and collect the required data needed to calculate and report GHG emissions.
A beginning date of January 1, 2010 would allow sufficient time to begin monitoring and collecting data because many of the parameters that would need to be monitored under the proposed rule are already monitored by facilities for process management and accounting reasons (e.g., feedstock input rates, production output, fuel purchases). In addition, the monitoring methods specified by the rule are already well-known and documented; and monitoring devices required by the rule are routinely available, in ready supply (e.g., flow meters, automatic data recorders), and in some cases already installed. These same monitoring devices are already required by other air quality programs with which many of these same facilities are already complying.
It is reasonable for new sources that start operation after January 1, 2010, to begin monitoring the first month of operation because new sources would be aware of the rule requirements when they design the facility and its processes and obtain permits. They can plan the data collection and reporting processes and install needed monitoring equipment as they build the facility and begin operating the monitoring equipment when they begin operating the facility.
We recognize that although the Agency plans to issue the final rule in sufficient time to begin monitoring on January 1, 2010, we may be unable to meet that goal. Therefore, we are interested in receiving comments on alternative effective dates, including the following two options:
• Report 2010 data in 2011 using best available data: Under this scenario, the rule would be effective January 1, 2010, allowing affected facilities to use either the methods in proposed 40 CFR part 98 or best available data. As in the current proposal, the report would be submitted on March 31, 2011, and then full data collection, using the methods in 40 CFR part 98 would begin in 2011, with that report sent to EPA on March 31, 2012. Under this approach, EPA solicits comment on the types of best available data and methods that should be allowed in 2010, by source category, (e.g., fuel consumption, emissions by process, default emissions factors, fuel receipts, etc.) as well as additional basic data that should be reported (e.g., facility name, location). This approach is similar to the CARB mandatory reporting rule, which allowed affected facilities to report 2009 emissions in 2010 using best available data, and then requires 2010 data collection in 2011 using the methods in the rule. The advantages of this approach are that the dates of the proposal remain intact and EPA receives basic information, including emissions and fuel data from all affected facilities in 2011. Furthermore, this approach can ease facilities into the program by giving them potentially a full year to implement the required methods and install any necessary equipment. For example, this option encourages the use of the methods in 40 CFR part 98 but if that is not possible, it allows the use of best available data (e.g., if a facility does not have a required flow meter installed for 2010 they can substitute the data from their fuel receipts in the calculation). The disadvantage of this approach is that it delays full data collection using the methods in the rule by 1 year from what is proposed. Further, in some cases, this approach could lead to data that is of lesser quality than the data we would receive using the methods in 40 CFR part 98. In other cases, because sources are already following the methods in 40 CFR part 98 (e.g., stationary combustion units in the ARP), the quality of the data would remain unchanged under this option. Given the objective of this rule to collect comprehensive and accurate data to inform future policies and the interest in Congress in developing climate change legislation, any delay in receiving that data could adversely affect the ability to inform those policies. That said, the data we would receive in 2011 under this option would at least provide basic information about the types, locations, emissions and fuel consumption from facilities in the United States.
• Report 2011 data in 2012: Under this scenario, the rule would require that affected facilities begin collecting data January 1, 2011 and submit the first reports to EPA on March 31, 2012. The methods in the proposed rule would remain unchanged and the only difference is that this option would delay implementation of the rule by one year. The advantages of this approach are that affected facilities would have a substantial amount of time to prepare for this reporting rule, including implementing the method and installing equipment. In addition, we would have even more time to conduct outreach and guidance to affected facilities. The disadvantages of this approach are that it delays implementation of this rule by a year and does not offer a mechanism for EPA to receive crucial data, even basic data, necessary to inform future policy and regulatory development. Furthermore, in some cases affected facilities are already implementing the methods required by proposed 40 CFR part 98 (e.g., stationary combustion units in the ARP) or are familiar with the methods, and have all of the necessary equipment or processes in place to monitor emissions consistent with the methods in 40 CFR part 98. Therefore, delaying implementation by a year not only deprives EPA of valuable data to support future policy development, but at the same time, does not provide any real advantage to these facilities.
Proposed 40 CFR part 98, subpart A, specifies numerical reporting thresholds for different direct emitters or supply
As discussed earlier, if a facility does not have any of the source categories listed in proposed 40 CFR 98.2 (a)(1) or (2), but has stationary combustion onsite that exceeds the GHG reporting threshold in 2010, they would still be required to estimate GHG emissions in 2010 and report in 2011. However, because those facilities would not contain any of the source categories specifically identified in proposed 40 CFR 98.2 (a)(1) or (2) and tend to be smaller facilities in diverse industrial sectors, they may require some extra time to implement the requirements of this rule. As such, they would be allowed to use an abbreviated facility report using simplified emission estimation methods for the first year (i.e., for calendar year 2010) and would not be required to complete a full report until the second reporting year (i.e., 2012).
The abbreviated report would allow the facility to use default fuel-specific CO
EPA proposes that the annual GHG emissions reports would be submitted no later than March 31 for the previous calendar year's reporting period. Three months is a reasonable time to compile and review the information needed for the annual GHG emissions report and to prepare and submit the report. The data needed to estimate emissions and compile the report would be collected by the facility on an ongoing basis throughout the year, so facilities could begin data summary during the year as the data are collected. For example, they could compile needed GHG calculation input data (e.g., fuel use or raw material consumption data) or emission data on a periodic basis (e.g., monthly or quarterly) throughout the year and then total it at the end of the year. Therefore, only the most recently collected information would need to be compiled and a final set of calculations would need to be performed before the final report is assembled. Given the nature of the methodologies contained in the rule, three months is sufficient time to calculate emissions, quality-assure, certify, and submit the data.
EPA is proposing that all affected facilities would have to submit annual GHG emission reports. Facilities with ARP units that report CO
We have determined that annual reporting is sufficient for policy development. It is consistent with other existing mandatory and voluntary GHG reporting programs at the State and Federal levels (e.g., TCR, several individual State mandatory GHG reporting rules, EPA voluntary partnership programs, the DOE voluntary GHG registry). However, as future policies develop it may be necessary to reconsider the reporting frequency and require more or less frequent reporting (e.g., quarterly or every few years). For example, under future programs or policy initiatives, particularly if regulatory in nature (e.g., a cap-and-trade program similar to the ARP) it may be more appropriate require quarterly reporting.
Generally, we propose that facilities report emissions for all source categories at the facility for which methods have been defined in any subpart of proposed 40 CFR part 98. Facilities would report (1) total annual GHG emissions in metric tons CO
Emissions would be reported at the level (facility, process, unit) at which the emission calculation methods are specified in each applicable subpart. For example, if a pulp and paper mill has three boilers and a wastewater treatment operation, the facility would report emissions for each boiler (according to the methodologies presented in proposed 40 CFR part 98, subpart C), the wastewater treatment operation (according to proposed 40 CFR part 98, subpart II), and from chemical recovery units, lime kilns, and makeup chemicals (according to proposed 40 CFR part 98, subpart AA). In addition, the report would include summary information on certain process operating data that influence the level of emissions and that are necessary to calculate GHG emissions and verify those calculations using the methodologies in the rule. Examples of these data include fuel type and amount, raw material inputs, or production output. The specific process information to report varies for each source category and is specified in each subpart.
Furthermore, in addition to any specific requirements for reporting emissions from electricity generation in Sections V.C and V.D of this preamble, EPA is proposing that all facilities and supply operations affected by this rule would also report the quantity of electricity generated onsite. The generation of onsite electricity can
We are also taking comment on, but not proposing at this time, requiring facilities and supply operations affected by the proposed rule to also report the quantity of electricity purchased. For many industrial facilities, purchased electricity represents a large part of onsite energy consumption, and their overall GHG emissions footprint when taking into account the indirect emissions from fossil fuel combusted for the electricity generated. Together, the reporting of electricity purchase data and onsite generation could provide a better understanding of how electricity is used in the economy and the major industry sectors.
Many existing reporting programs require reporting of indirect emissions (e.g., Climate Leaders, CARB, TCR, DOE 1605(b) program). In general, the protocols for these programs follow the methods developed by WRI/WBCSD for the quantification and reporting of indirect emissions from the purchase of electricity. The WRI/WBCSD protocol outlines three scopes to help delineate direct and indirect emission sources, with the stated goal to improve transparency, and provide utility for different types of organizations and different types of climate policies and business goals. Scope 1 includes direct GHG emissions occurring from sources that are owned or controlled by the business. Scope 2 includes indirect GHG emissions resulting from the generation of purchased electricity, heat, and/or steam. Scope 3 is optional and includes other types of indirect emissions (e.g., from production of purchased materials, waste disposal or employee transportation).
We are taking comment on, but not proposing at this time, an approach that would require the reporting of electricity purchase data, and not indirect emissions, because these data are more readily available to all facilities. Through the review of existing reporting programs that require the reporting of indirect emissions data it was determined that there are multiple ways proposed to calculate indirect emissions from electricity purchases. This reflects the challenge associated with determining the specific fossil fuel mix used to generate the electricity consumed by a facility, and thus the indirect emissions that should be attributed to the facility. Although indirect emissions data would not be directly reported under this approach, it would enable indirect emissions for facilities to be calculated. This option also would be the least burdensome to reporting facilities since the data would be easily available.
The information that is proposed to be reported reflects the data that could support analyses of GHG emissions for future policy development and ensure the data are accurate and comparable across source categories. Besides total facility emissions, it benefits policymakers to understand: (1) The specific sources of the emissions and the amounts emitted by each unit/process to effectively interpret the data, and (2) the effect of different processes, fuels, and feedstocks on emissions. This level of reporting should not be overly burdensome because many of these data already are routinely monitored and recorded by facilities for business reasons. The remainder of the reported data would need to be collected to determine GHG emissions.
The report would contain a signed certification from a representative designated by the owner or operator of a facility affected by this rule. This “Designated Representative” would act as a legal representative between the source and the Agency. The use of the Designated Representative would simplify the administration of the program while ensuring the accountability of an owner or operator for emission reports and other requirements of the mandatory GHG reporting rule. The Designated Representative would certify that data submitted are complete, true, and accurate. The Designated Representative could appoint an alternate to act on their behalf, but the Designated Representative would maintain legal responsibility for the submission of complete, true, and accurate emissions data and supplemental data.
Besides these general reporting requirements, the specific reporting requirements for each source category are described in the methodological discussions in Section V of this preamble.
A number of existing GHG reporting programs contain “de minimis” provisions. The goal of a de minimis provision is to avoid imposing excessive reporting costs on minor emission points that can be burdensome or infeasible to monitor. Existing GHG reporting programs recognize that it may not be possible or efficient to specify the reporting methods for every source that must be reported and, therefore, have some type of provision to reduce the burden for smaller emissions sources. Depending on the program, the reporter is allowed to either not report a subset of emissions (e.g., 2 to 5 percent of facility-level emissions) or use simplified calculation methods for de minimis sources.
We analyzed the de minimis provisions of existing reporting rules and concluded that there is no need to exclude a percentage of emissions from reporting under this proposal. EPA recognizes the potential burden of reporting emissions for smaller sources. The proposal addresses this concern in several ways. First, only those facilities over the established thresholds would be required to report. Smaller facilities would not be subject to the program. Second, for those facilities subject to the rule, only emissions from those source categories for which methods are provided would be reported. Methods are not proposed for what are typically smaller sources of emissions (e.g., coal piles on industrial sites). Third, because some facilities subject to the rule could still have some relatively small sources, the proposal includes simplified emissions estimation methods for smaller sources, where appropriate. For example, small stationary combustion units could use a default emission factor and heat rate to estimate emissions, and no fuel measurements would be required. Where simplified methods are proposed, they are described in the relevant discussions in Section V of this preamble.
Our analysis showed that the GHG reporting programs with de minimis exclusions are structured differently than our proposed rule. For example, most rules with de minimis exclusions require corporate level reporting of all emission sources. Under these programs, some corporations must report emissions from numerous remote facilities and must report emissions from small onsite equipment (e.g., lawn mowers). For these programs, a de minimis exclusion avoids potentially
For additional information on the treatment of de minimis in existing GHG reporting programs, please refer to the “Reporting Methods for Small Emission Points (De Minimis Reporting)” (EPA–HQ–OAR–2008–0508–048).
Most voluntary and mandatory GHG reporting programs include provisions for operators to revise previously submitted data. For example, some voluntary programs require reporters to revise their base year emissions calculations if there is a significant change in the boundary of a reporter, a change in methodologies or input data, a calculation error, or a combination of the above that leads to a significant change in emissions. Recalculation procedures particularly appear to be central in voluntary GHG reporting programs that are also tracking emissions reductions.
Moreover, some programs (e.g., ARP) have detailed provisions for filling in data gaps that are missing in the required report. For example, in ARP, these procedures apply when CEMS are not functioning and as a result several hours of the required hourly data are missing. Note, however, that merely filling in data gaps that are missing or correcting calculation errors does not relieve an operator from liability for failure to properly calculate, monitor and test as required.
For this mandatory GHG reporting program, EPA concluded it was important to have missing data procedures in order to ensure there is a complete report of emissions from a particular facility. However, because this program requires annual reporting rather than quarterly reporting of hourly data as in ARP, the missing data provision often require the facility to redo the test or calculation of emissions. Section V of the preamble details the missing data procedures for facilities reporting to this program. EPA is seeking comment on whether to include a provision to require a minimum standard for reported data (e.g., only 10 percent of the data reported can be generated using missing data procedures).
In addition to establishing procedures for missing data, there may be benefit in requiring previously submitted data to be recalculated in order to ensure that the GHG emissions reported by a facility are as accurate as possible. The proposed California mandatory GHG reporting program, for example, allows reporters to revise submitted emissions data if errors are identified, subject to approval by the program.
EPA is considering whether or not to include provisions to require facilities to correct previously submitted data under certain circumstances. However, these benefits must also be weighed against the additional costs associated with requiring reporters to recalculate and resubmit previous data, and the magnitude of the emissions changes expected from such recalculations. Moreover, even if EPA were to allow recalculation of submitted data or accept data submitted using missing data procedures, that would not relieve the reporter of their obligation to report data that are complete, accurate and in accordance with the requirements of this rule. Although submitting recalculated data or data using missing data procedures would correct the data that are wrong, that resubmission or missing data procedures does not necessarily reverse the potential rule violation and would not relieve the reporter of any penalties associated with that violation. EPA is seeking comment on whether the mandatory GHG reporting program should include provisions to require reporters to submit recalculated data and under what circumstances such recalculations should be required.
In selecting the monitoring requirements for the proposed rule, EPA's goal is to collect data of sufficient accuracy and quality to be used to inform future climate policy development and support a range of possible policies and regulations. Future policies and regulations could range from research and development initiatives to regulatory programs (
Direct measurement is not technically feasible in all cases. For example, CEMS are not available for many of the GHGs that must be reported. Direct measurement is also infeasible for emissions that are not captured and emitted through a stack, such as CH
The direct measurement option has the highest degree of certainty of the data reported. It is also the most costly because all facilities where direct measurement is feasible would need to install, operate, and maintain emission monitors. Most facilities currently do not have CEMS to measure GHG emissions.
Facilities that do not have units that have CEMS installed would have the choice to either directly measure emissions or to use facility-specific GHG calculation methods. The measurement and calculation methods for each source category would be specified in each subpart. Depending on the source category, methods could include mass balance; measurement of the facility's use of fuels, raw materials, or additives combined with site-specific measured carbon content of these materials; or other procedures that rely on facility-specific data. For the supplier source categories (e.g., those that supply fuels or industrial GHGs), this option would require reporting of production, import, and export data. The supplier companies already closely track these data for financial and other reasons.
This option provides a relatively high degree of certainty and takes advantage of existing practices at facilities. This option is less costly than option 1 because most facilities are not required to install CEMS and can, in many cases, make use of data they are already collecting for other reasons.
Under this option, the only facilities that would have to use more rigorous monitoring or site-specific calculations methods are facilities that are already required to report emissions under 40 CFR part 75. These facilities would continue to follow the CO
Data collected under this option would have a lower degree of certainty than options 1 or 2. Furthermore, many facilities are already calculating GHG emissions to a higher degree of certainty for business reasons or for other mandatory or voluntary reporting programs, and option 3 would not make use of such available data. However, the cost to facilities is lower than under options 1 and 2.
Data collected under this option would not be comparable across a given industry and across reporters subject to the program, thereby minimizing the usefulness of the data to support future policymaking. Although some facilities might choose to use direct measurement because CEMS are already installed at the facility, other facilities would select default calculations. This option would be the lowest cost to reporters.
Option 2 strikes a balance between data accuracy and cost. It makes use of existing data and methodologies to the extent feasible, and avoids the cost of installing and operating CEMS at numerous facilities. It is consistent with the types of methods contained in other GHG reporting programs (e.g., TCR, California programs, Climate Leaders). Because this option specifies methods for each source category, it should result in data that are comparable across facilities.
Option 1 (direct emission measurement) was not chosen because the cost to the reporters if all facilities had to install continuous emission monitoring systems would be unreasonably high in the absence of a defined policy that would require this type of monitoring. However, under the selected option, facilities that already use CEMS would still be required to use them for purposes of the GHG reporting rule.
Option 3 (simplified calculation methods) was not chosen because the data would be less accurate than option 2 and would not make use of site-specific data that many facilities already have available and refined calculation approaches that many facilities are already using. Option 3 would also be inconsistent with several other GHG reporting programs such as TCR and California programs that contain more site-specific calculation methods for several of the source categories.
Option 4 (reporter's choice of methods) was not proposed because the accuracy and reliability of the reported data would be unknown and would vary from one reporter to the next. Because consistent methods would not be used under this option, the reported data would not be comparable across similar facilities. The lack of comparability would undermine the use of the data to support policy decisions.
EPA requests comments on the selected monitoring approach and on other potential options and their advantages and disadvantages.
EPA is proposing that each facility that would be required to submit an annual GHG report would also keep the following records, in addition to any records prescribed in each applicable subpart:
• A list of all units, operations, processes and activities for which GHG emissions are calculated;
• The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type;
• Documentation of the process used to collect the necessary data for the GHG emissions calculations;
• The GHG emissions calculations and methods used;
• All emission factors used for the GHG emissions calculations;
• Any facility operating data or process information used for the GHG emissions calculations;
• Names and documentation of key facility personnel involved in calculating and reporting the GHG emissions;
• The annual GHG emissions reports;
• A log book documenting any procedural changes to the GHG emissions accounting methods and any changes to the instrumentation critical to GHG emissions calculations;
• Missing data computations;
• A written QAPP;
• Any other data specified in any applicable subpart of proposed 40 CFR part 98. Examples of such data could
These data are needed to verify the accuracy of reported GHG emission calculations and, if needed, to reproduce GHG emission estimates using the methods prescribed in the proposed rule. Since the above information must be collected in order to calculate GHG emissions, the added burden of maintaining records of that information should be minimal.
Each facility would be required to retain all required records for at least 5 years. Records would be maintained for this period so that a history of compliance could be demonstrated and questions about past emission estimates could be resolved, if needed.
The records would be required to be kept in an electronic or hard-copy format (as appropriate) that is readily accessible within a reasonable time for onsite inspection and auditing. They would be recorded in a form that can be easily inspected and reviewed. The allowance of a variety of electronic and hard copy formats for records allows flexibility for facilities to use a system that meets their needs and is consistent with other facility records maintenance practices, thereby minimizing the recordkeeping burden.
GHG emissions reported under this rule would be verified to ensure accuracy and completeness so that EPA and the public could be confident in using the data for developing climate policies and potential future regulations. To ensure the completeness and quality of data reported to the program, the Agency proposes self-certification with EPA verification. Under this approach, all reporters subject to this rule would certify that the information they submit to EPA is truthful, accurate and complete. EPA would then review the emissions data and supporting data submitted by reporters to verify that the GHG emission reports are complete, accurate, and meet the reporting requirements of this rule.
Given the scope of this rulemaking, this approach is consistent with many EPA regulatory programs. That said, this proposal does not preclude that in the future, as climate policies evolve, EPA may consider third party verification for other programs (e.g., offsets). Furthermore, many programs in the States and Regions may be broader in scope and the use of third party verifiers may be appropriate to meet the needs of those programs.
In addition, under the authorities of CAA sections 114 and 208, EPA has the authority to independently conduct site visits to observe monitoring procedures, review records, and verify compliance with this rule (see Section VII of this preamble for further information on compliance and enforcement). For vehicle and engine manufacturers, EPA is not proposing additional verification requirements beyond the current emissions testing and certification procedures. These procedures include well-established methods for assuring the completeness and quality of reported emission test data and EPA is proposing to include the new GHG reporting requirements as part of these methods.
In selecting this proposed approach to verification, the Agency reviewed verification requirements and procedures under a number of existing EPA regulatory programs, as well as existing domestic and international GHG reporting programs. Additional information on this review and the verification approaches can be found in a technical memorandum (“Review of Verification Systems in Environmental Reporting Programs,” EPA–HQ–OAR–2008–0508–047). Based on this review, EPA considered three alternative approaches to verification: (1) Self-certification without independent verification, (2) self-certification with third-party verification, and (3) self-certification with EPA verification.
Option 1 is a low burden option for reporters submitting data for this rule. Reporters under this option would not have to pay for third-party verifiers and would not necessarily have to submit the additional data required under the other options. In addition, EPA would not incur the expense of conducting verification of the reported data or certifying independent verifiers to conduct verification activities. The major disadvantages of this approach are the greater potential for inconsistent and inaccurate data in the absence of independent verification and the lower level of confidence that the public, stakeholders and EPA may have in the data.
Self-certification with third-party verification provides greater assurance of accuracy and impartiality than self-certification without verification. While this option is consistent with some existing domestic and international GHG reporting programs such as TCR, the California mandatory reporting rule, CCAR, and the EU Emission Trading System, the majority of industry stakeholders that met with EPA are opposed to this approach for this rulemaking, primarily due to the additional cost. Compared to option 1, the third-party verification approach places two additional costs on reporters: (1) Reporters would need to hire and pay verifiers, at a cost of thousands of dollars per reporting facility, and (2) reporters would incur costs to assemble
To ensure consistency and quality of the third-party verifications, EPA would need to develop verification protocols, establish a system to qualify and accredit the third-party verifiers, and conduct ongoing oversight and auditing of verifications to be sure that third-party verifications continue to be conducted in a consistent and high quality manner.
As mentioned above, as climate policy evolves, it may be appropriate for EPA to consider the use of third party verification in other circumstances (e.g., offsets).
EPA verification provides greater assurance of accuracy and impartiality than self-reporting without verification. Compared to a third-party verification system, there would be a consistent approach to verification from one centralized verifier rather than a variety of separate verifiers although this option would require EPA to ensure consistency if it chose to use its own contractors to support its verification activities. In addition, a centralized verification system would provide greater ability to the government to identify trends and outliers in data and thus assist with targeted enforcement planning. Finally, an EPA verification approach is consistent with other EPA emissions reporting programs including EPA's ARP.
EPA is proposing self-certification with EPA verification (option 3) because it ensures that data reported under this rule are consistent, accurate, and complete. In addition, we are seeking comment on requiring third-party verification for suppliers of petroleum products, many of whom currently report to EPA under the Office of Transportation and Air Quality's fuels programs. Third-party verification could be reasonable in these instances because this rule, to some extent, would build on existing transportation fuels programs that already require audits of records maintained by these suppliers by independent certified public accountants or certified internal auditors. For more information about the approach to fuel suppliers please refer to Section V of this preamble.
EPA is successfully using self certification with EPA verification in a number of other emissions reporting programs. EPA verification option provides greater assurance of the accuracy, completeness, and consistency of the reported data than option 1 (no independent verification) and consistent with feedback from industry stakeholders, does not require reporters to hire third-party verifiers (option 2). In addition, EPA verification option does not require the establishment of an accreditation and approval program for third-party verifiers although it would require EPA to ensure consistency if it chose to use its own contractors to support its verification activities.
EPA judged that option 1 (no independent verification) does not ensure sufficient quality data for the possible future uses of the data. The potential inconsistency, inaccuracy, and increased uncertainty of the data collected under option 1 would make the data less useful for informing decisions on climate policy and supporting the development of a wide range of potential future policies and regulations.
We selected EPA verification (option 3) instead of third-party verification (option 2) because EPA verification is consistent with other EPA programs, has lower costs to reporters than option 2, and would result in a consistent verification approach applied to all submitted data. Even with a verifier accreditation and approval process, the third-party verification approach could entail a risk of inconsistent verifications because verification responsibilities are spread amongst numerous verifiers. Given the potential diversity of verifiers, the quality and thoroughness of verifications may be inconsistent and EPA audit and enforcement oversight would become the predominant factor in ensuring uniformity. Under option 2, EPA would also need to develop and administer a process to ensure that verifiers hired by the reporting facilities do not have conflicts of interest. Such a program could require EPA to review numerous individual conflict of interest screening determinations made each time a reporter hires a third-party verifier. Finally, EPA verification would likely avoid any delays that may be introduced by third-party verification and better ensure the timely reporting and use of the reported data. Some reporting programs provide four to six months after the annual emissions report is submitted for third-party verification. That said, as mentioned above, depending on the scope or type of program (e.g., offsets), EPA may consider the use of third party verification in the future as policy options evolve.
The Agency recognizes that, in some instances, data submitted by reporters under this rule may have been independently verified as the result of other mandatory or voluntary GHG reporting programs or by other Federal, State or local regulations. Whether or not data have been independently verified outside of the requirements of this proposed GHG reporting rule, EPA has concluded for the purposes of this proposal it is important to apply the same verification requirements to all affected facilities in order to ensure equity across all reporters and consistent data collection for policy analysis and public information.
EPA is proposing that the rule require the reporting of GHG emissions data on an ongoing, annual basis. Other approaches that EPA considered include a one-time collection of information and collection of a limited duration (e.g., a three-year data collection effort).
EPA does not believe that a one-time data collection effort is consistent with the legislative history of the FY 2008 Consolidated Appropriations Act, which instructed EPA to develop a rule to require the reporting of GHG emissions. Typically, a rule is not required to undertake a one-time information collection request. Moreover, the President's FY 2010
For example, on February 6, 2009, Senators Feinstein, Boxer, Snowe and Klobuchar sent a letter to EPA's Administrator Lisa Jackson and OMB's Director Peter Orszag stating that this program allowed EPA to “gather critical baseline data on greenhouse gas emissions, which is essential information that policymakers need to craft an effective climate change approach.” In addition, in recent testimony from John Stephenson, Director of Natural Resources and Environment at the Government Accountability Office,
EPA also considered a multi-year program that would sunset at a date certain in the future (e.g., three years) absent subsequent regulatory action by EPA to extend it. EPA decided against this approach because it would unnecessarily limit the debate about potential policy options to address climate change. At this time, it would be premature to guess at what point in the future this information may be less relevant to decision-making. Rather, a more prudent approach is to maintain the program until such time in the future when it is determined that the information for one or more source categories is no longer relevant to decision-making, or is adequately provided in the context of regulatory program (e.g., CAA NSPS). Notably, EPA crafted the requirements in this rule with the potential monitoring, recordkeeping and reporting requirements for any future regulations addressing GHG emissions in mind. EPA solicits comment on all of these possible approaches, including whether EPA should commit to revisit the continued necessity of the reporting program at a future date.
Section V of this preamble discusses the source categories covered by the proposed rule. Each section presents a description of a source category and the proposed threshold, monitoring methods, missing data procedures, and reporting and recordkeeping requirements.
Once you have determined that your facility exceeds any reporting threshold specified in 40 CFR 98.2(a), you would have to calculate and report GHG emissions, or alternate information as required (e.g., production and imports for industrial GHG suppliers) for all source categories at your facility for which there are measurement methods provided. The threshold determination is separately assessed for suppliers (fossil fuel suppliers and industrial GHG suppliers) and downstream source categories.
Facilities, or corporations, where relevant, that trigger only the threshold for upstream fossil fuel or industrial GHG supply (proposed 40 CFR part 98, subparts KK through PP) need only follow the methods in those respective sections. Facilities (or corporations) that contain source categories that also have downstream sources of emissions (e.g., proposed 40 CFR part 98, subparts B through JJ), or facilities that are exclusively downstream sources of emissions may have to monitor and report GHG emissions using methods presented in multiple sections. For example, a food processing facility should review Section V.C (General Stationary Fuel Combustion), Section V.HH (Landfills) and Section V.II (Wastewater Treatment) in addition to Section V.M (Food Processing) of this preamble. Table 2 of this preamble (in the
Consistent with the requirements in the proposed 40 CFR part 98, subpart A, facilities would have to report GHG emissions from all source categories located at their facility—stationary combustion, process (e.g., iron and steel), fugitive (e.g., oil and gas) or biologic (e.g., landfills) sources of GHG emissions. The methods presented typically account for normal operating conditions, as well as SSM, where significant (e.g., HCFC–22 production and oil and gas systems). Although SSM is not specifically addressed for many source categories, emissions estimation methodologies relying on CEMS or mass balance approaches would capture these different operating conditions.
For many facilities, calculating facility-wide emissions would simply involve adding GHG emissions calculated under Section V.C of this preamble (General Stationary Fuel Combustion Sources) and emissions calculated under the source-specific subpart. For other facilities, particularly selected sources in Sections V.E through V.JJ of this preamble that rely on mass balance approaches or the use of CEMS, the proposed methods would (depending on the operating conditions and configuration of the plant) capture both combustion and process-related emissions and there is no need to separately quantify combustion-related emissions using the methods presented in Section V.C of this preamble.
Generally, the proposed method depends on the equipment you currently have installed at the facility.
(1) Where the CEMS capture both combustion- and process-related emissions you would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate emissions from the industrial source. In this case, use of the additional methods provided in the source-specific discussions would not be required.
(2) Where the CEMS do not capture both combustion and process-related emissions, you should refer to the source-specific sections that provide methods for calculating process emissions. You would also be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate any stationary fuel combustion emissions from the industrial source.
At this time, we are not proposing that facilities report information to us regarding their electricity purchases or indirect emissions from electricity consumption. However, we carefully considered proposing that all facilities that report to us also report their total purchases of electricity. This section describes our deliberations and outlines potential methods for monitoring and reporting electricity purchases. We generally seek comment on the value of collecting information on electricity purchases. Further, we are specifically interested in receiving feedback on the approach outlined below.
The electric utility sector is the largest emitter of GHG emissions in the U.S. The level of GHG emissions associated with electricity use is determined not just by the fuel and combustion technology onsite at the power plant, but also by customer demand for electricity. Accordingly, electricity use and the efficiency of this use indirectly affect the emissions of CO
For many facilities, purchased electricity represents a large part of onsite energy consumption, and their overall GHG emissions footprint when taking into account the indirect emissions from fossil fuel combusted for the electricity generated. Therefore, the reporting of electricity purchase data from facilities could provide a better understanding of how electricity is used in the economy and the major sectors. We would propose not to provide for adjustments to take into account the purchases of renewable energy credits or other mechanisms.
If included, this source category would include electricity purchases, but not include electricity generated onsite (i.e., facility-operated power plants, emergency back-up generators, or any portable, temporary, or other process internal combustion engines). General requirements for all reporters subject to the proposed rule to report on total kilowatt hours of electricity generated onsite is discussed in Section IV.G of the preamble. Calculating emissions from onsite electricity generation is addressed in Sections V.C and V.D of this preamble.
For additional background information on indirect emissions from electricity purchases, please refer to the Electricity Purchases TSD (EPA–HQ–OAR–2008–0508–003).
Three options for reporting thresholds could be considered for the reporting of indirect emissions from purchased electricity (i.e., GHG emissions from the production of purchased electricity). These options would be as follows:
No additional facilities to those already reporting their emissions data under this rule would be affected by the first or second options. The number of additional facilities affected by the third proposed threshold is estimated to be approximately: 250 facilities at a 100,000 metric tons CO
Under all threshold options, reporting of information related to electricity purchases would apply to entities reporting at the facility level. This provision would not apply to source categories that we propose report at the corporate level (e.g., importers and exporters of industrial GHGs, local distribution companies, etc.). These companies in many cases may own large facilities such as refineries which already have a reporting obligation for direct emissions and electricity purchases.
Given the above considerations, our preferred option would be option 2. Purchased electricity is considered to be a significant portion of the GHG emissions of most industrial facilities, therefore the collection of indirect emissions from purchased electricity could be seen as an important component of the GHG mandatory reporting rule. Although such a reporting requirement would not provide EPA with emissions information, it could provide the necessary underlying data to develop emissions estimates in the future if this were necessary.
The reporting of electricity purchase data directly instead of calculated indirect emissions would be preferred due to the difficulties in identifying the appropriate electrical grid or electrical plant emission factor for converting a facility's electricity purchases to GHG emissions. EPA does not have data to evaluate the uncertainty of applying national, regional or State emission factors to electricity consumption at a given facility, versus undertaking detailed studies to determine the actual emissions from electricity purchases.
Under Option 2, all facilities that are already required to report their GHG emissions under this rule would also have to quantify and report their annual electricity purchases. The total purchased electricity would include electricity purchased from all sources (i.e., fossil fuel power plants, green power generating facilities, etc.). It should be noted that under this approach, data from large sources of indirect emissions due to electricity
Purchased electricity could be quantified through the use of purchase receipts or similar records provided by the electricity provider. The facility could choose to use data from facility maintained electric meters in addition to or in lieu of data from an electricity provider (e.g., electricity purchase receipts, etc.), provided that this data could be demonstrated to accurately reflect facility electricity purchases. However, purchase receipts or electricity provider data would be the preferred method of quantifying a facility's electricity purchases. Because facilities would be expected to retain these data as part of routine financial records, the only additional burden of collecting this information would be to retain the records in a readily available manner.
In identifying the options outlined above, we reviewed five reporting programs and guidelines: (1) EPA Climate Leaders Program, (2) the CARB Mandatory Greenhouse Gas Emissions Program, (3) TRI, (4) the DOE 1605(b) program, and (5) the GHG Protocol developed jointly by WRI and WBCSD. In general, these protocols follow the methods presented in WRI/WBCSD for the quantification and reporting of indirect emissions from the purchase of electricity.
See the Electricity Purchases TSD (EPA–HQ–OAR–2008–0508–003) for more information.
If we were to collect information on electricity purchases, we would propose that a facility be required to make all attempts to collect electricity records from their electricity provider. In the event that there were missing electricity purchase records, the facility would estimate its electricity purchases for the missing data period based on historical data (i.e., previous electricity purchase records). Any historical data used to estimate missing data should represent similar circumstances to the period over which data are missing (e.g., seasonal). If a facility were using electric meter data and had a missing data period, the facility could use a substitute data value developed by averaging the quality-assured values metered values for kilowatt-hours of electricity use immediately before and immediately after the missing data period.
If we were to collect information on electricity purchases, we would propose that a facility report total annual purchased electricity in kilowatt-hours for the entire facility.
If we were to collect information on electricity purchases, we would propose that the owner or operator maintain monthly electricity purchase records for all operations and buildings. If electric meter data were used, then monthly logs of the electric meter readings would also be proposed to be maintained.
Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, combustion turbines, engines, incinerators, and process heaters. The combustion process may be used to: (a) Generate steam or produce useful heat or energy for industrial, commercial, or institutional use; (b) produce electricity; or (c) reduce the volume of waste by removing combustible matter. As discussed in Section III of this preamble and proposed 40 CFR part 98, subpart A, this section applies to facilities with stationary fuel combustion sources that (a) have emissions greater than or equal to 25,000 metric tons CO
Combustion of fossil fuels in the U.S. is the largest source of GHG emissions in the nation, producing three principal greenhouse gases: CO
A wide and diverse segment of the U.S. economy engages in stationary combustion, principally the combustion of fossil fuels. According to the “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2006”, the nationwide GHG emissions from stationary fossil fuel combustion are approximately 3.75 billion metric tons CO
EPA's proposed rule presents methods for calculating GHG emissions from stationary combustion, both at unspecified facilities as well as facilities in source categories listed in proposed 40 CFR 98.2(a)(1) and (2), which are based on the fuel combusted and the size of the stationary equipment (e.g., the maximum heat input capacity in mmBtu/hr). EPA already collects CO
Table C–1 of this preamble illustrates the methods for calculating CO
In developing the threshold for facilities with stationary combustion equipment, EPA considered an emissions-based threshold of 1,000, 10,000, 25,000, and 100,000 metric tons CO
In calculating emissions for this analysis, and for the proposed threshold, only CO
The purpose of the general stationary combustion source category is to capture significant emitters of stationary combustion GHG emissions that are not covered by the specific source categories described elsewhere in this preamble. Therefore, EPA is proposing a threshold for reporting emissions from stationary combustion at 25,000 metric tons CO
The 100,000 metric tons CO
The 10,000 metric tons CO
In addition, although there is considerable uncertainty as to the number of facilities under a 25,000 metric tons CO
EPA concluded that a 25,000 metric tons CO
EPA also considered including GHG emissions from the combustion of biomass fuels in the emission threshold calculations. Therefore, the proposed rule states that GHG emissions from biomass fuel combustion are to be excluded when evaluating a facility's status with respect to the 25,000 metric tons CO
Finally, EPA considered a heat input capacity-based threshold (such as all facilities with stationary combustion equipment rated over 100 mmBtu/hr maximum heat input capacity). A complete, reliable set of heat input capacity data was unavailable for all facilities that might be subject to this rule, thus this type of threshold could not be thoroughly evaluated.
For a full discussion of the threshold analysis and for background information on this threshold determination, please refer to the Thresholds TSD (EPA–HQ–OAR–2008–0508–046). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
EPA's proposed methods for calculating GHG emissions from stationary fuel combustion sources is consistent with existing domestic and international protocols, as well as monitoring programs currently implemented by EPA. Those protocols and programs generally utilize either a direct measurement approach based on concentrations of combustion exhaust gases through a stack, or a direct measurement approach based on the quantity of fuel combusted and the characteristics of the fuel (e.g., heat content, carbon content, etc.). As the magnitude of CO
For facilities which have EGUs subject to the ARP reporting requirements under 40 CFR part 75, refer to Section V.D of this preamble regarding those units. For other units located at that facility (i.e., units that are not reporting to the ARP), the facility would use the calculation methods presented below.
The discussions which follow in this subsection will focus on methods for: (a) The calculation of CO
To monitor and calculate CO
The next level of methodological stringency applies to large stationary combustion units that are fired with liquid or gaseous fuels. The stringency of the methods reflects the homogenous nature of these fuels and the ability to monitor fuel consumption more precisely. However, in cases where there is greater heterogeneity in the fuels (e.g., refinery fuel gas) more frequent analyses of liquid and gaseous fuels is required.
For smaller combustion units, EPA is proposing to allow the use of more simplified emissions calculation methods that rely on relationships between the heat content of the fuel (a generally known parameter) and the CO
The following subsections present EPA's proposed four-tiered approach in order from the most rigorous to the least stringent, and describe how it must be used by affected facilities. The applicability of the four measurement tiers, based on unit size and fuel type, is summarized in Table C–1 of this preamble. These CO
Any CEMS that would be used to quantify CO
The Tier 4 method, and the use of CEMS (with any required monitor upgrades), is required for solid fossil fuel-fired units with a maximum heat input capacity greater than 250 mmBtu/hr (and for units with a capacity to combust greater than 250 tons per day of MSW). The use of an O
For smaller solid fossil fuel-fired units (i.e., less than or equal to 250 mmBtu/hr or 250 tons per day of MSW), EPA would require the use of Tier 4 if all the monitors needed to calculate CO
In addition, in order to be subject to the Tier 4 requirements, the unit must have been operated for 1,000 hours or more in any calendar year since 2005.
The incremental cost of adding a diluent gas (CO
Reporters would follow the reporting requirements stated in proposed 40 CFR part 98, subpart A. However, EPA is allowing a January 1, 2011 compliance date to install CEMS to meet the Tier 4 requirements, if either a diluent gas monitor, flow monitor, or both, must be added. The January 1, 2011 deadline would allow sufficient time to purchase, install, and certify any additional monitor(s) needed to quantify CO
The required frequency for carbon content determinations for the Tier 3 calculation methodology would be monthly for natural gas, liquid fuels, and solid fuels (monthly molecular weight determinations are also required for gaseous fuels). Daily determinations for other gaseous fuels (e.g., refinery gas, process gas, etc.) would be required. The daily fuel sampling requirement for units that combust “other” gaseous fuels would likely not be overly burdensome, because the types of facilities that burn these fuels are likely to have equipment in place (e.g., on-line gas chromatographs) to continuously monitor the fuels' characteristics in order to optimize process operation. Solid fuel samples would be taken weekly and composited, but would only be analyzed once a month. Also, fuel sampling and analysis would be required only for those days or months when fuel is combusted in the unit.
For liquid and gaseous fuels, Tier 3 would require direct measurement of the amount of fuel combusted, using calibrated fuel flow meters. Alternatively, for fuel oil, tank drop measurements could be used. Solid fuel consumption would be quantified using company records. For quality-assurance purposes, EPA proposes that all oil and gas flow meters would have to be calibrated prior to the first reporting year. EPA recommends the use of the fuel flow meter calibration methods in 40 CFR part 75, but, alternatively, the manufacturer's recommended procedure could be used. Tank drop measurements and carbon content determinations would be made using the appropriate methods incorporated by reference.
EPA considered several alternative CO
For coal combustion, EPA evaluated a number of calculation methods used in other mandatory and voluntary GHG emissions reporting programs. In general, these methods require relatively infrequent fuel sampling, do not take into account the heat input capacity of stationary combustion equipment, and use company records to estimate fuel consumption. Given the heterogeneous characteristics of coal, EPA determined that the procedures used in these other programs are not rigorous enough for this proposed rule and would introduce significant uncertainty into the CO
EPA considered allowing the use of default emission factors, default HHVs, and company records to quantify annual fuel consumption for all stationary combustion units, regardless of size or the type of fuel combusted. The Agency decided to limit the use of this type of calculation methodology to smaller combustion units. The proposed rule reflects this, by allowing use of the Tier 1 and Tier 2 calculation methodologies at units with a maximum heat input capacity of 250 mmBtu/hr or less.
For gaseous fuel combustion, EPA considered calculation methodologies based on an assumption that all gaseous fuels are homogeneous. However, the Agency decided against this approach because the characteristics of certain gaseous fuels can be quite variable, and mixtures of gaseous fuels are often heterogeneous in composition. Therefore, the proposed rule requires daily sampling for all gaseous fuels except for natural gas.
Finally, EPA considered allowing affected facilities to rely exclusively on the results of fuel sampling and analysis provided by fuel suppliers, rather than performing periodic on-site sampling for all variables. The Agency decided not to propose this because in most instances, only the fuel heating value, not the carbon content, is routinely provided by fuel suppliers. Therefore, EPA proposes to allow fuel suppliers to provide fuel HHVs for the Tier 2 calculation method. However, EPA is requesting comment on integrating the fuel supplier requirements of this proposed rule with both the Tier 1 and Tier 2 calculation methodologies.
Today's proposed rule requires affected facilities with units that combust biomass fuels to report the annual biogenic CO
Where Tier 4 is not required, EPA is allowing the Tier 1 method to be used to calculate biogenic CO
For units required to use Tier 4, total CO
EPA is proposing a separate calculation method for a unit that
The GHG emission calculation methods for units combusting MSW would be used in conjunction with EPA's proposed calculation method for the annual unit heat input, based on steam production and the design characteristics of the combustion unit.
For units that combust MSW, EPA considered allowing a manual sorting approach to be used to determine the biomass and non-biomass fractions of the fuel, based on defined and traceable input streams. However, this approach is not considered practical, given the highly variable composition of MSW. To eliminate this uncertainty, EPA believes that more rigorous and standardized ASTM methods should be used to determine the biogenic percentage of the CO
As described previously, EPA is allowing simplified emissions calculation methods for CH
A CEMS methodology was not selected for measuring N
EPA considered requiring periodic stack testing to derive site-specific emission factors for CH
For fluidized bed boilers and for units equipped with flue gas desulfurization systems or other acid gas emission controls with sorbent injection, CO
In summary, EPA is proposing to allow facilities flexibility in measuring and monitoring stationary fuel combustion sources by: (1) Allowing most smaller combustion units (depending upon facility-level considerations described above) to use the Tier 1 and Tier 2 calculation methods; (2) allowing Tier 3 to be widely used, with few restrictions; (3) limiting the requirement to use Tier 4 to certain solid fuel-fired combustion units located at facilities where there is an established monitoring infrastructure; and (4) allowing simplified methodologies to calculate CH
EPA believes that the proposed default CO
In proposing this tiered approach, EPA acknowledges that, in the case of solid fuels, a simple, standardized way of measuring the amount of solid fuel combusted in a unit is not proposed. In view of this, the proposed rule would require the owner or operator to keep detailed records explaining how company records are used to quantify solid fuel usage. These records would describe the procedures used to calibrate weighing equipment and other measurement devices, and would include scientifically-based estimates of the accuracy of these devices. EPA therefore solicits comment on ways to ensure that the feed rate of solid fuel to a combustion device is accurately measured.
The proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, commonly referred to as “missing data.” For units using the CO
EPA considered more conservative missing data procedures for the proposed rule, such as requiring higher substitute data values for longer missing data periods, but decided against proposing these procedures out of concern that GHG emissions might be significantly overestimated.
In addition to the facility-level information that would be reported under proposed 40 CFR part 98, subpart A, the proposed rule would require the reporter to submit certain unit-level data for the stationary combustion units at each affected facility. This additional information would require reporting of the unit type, its maximum rated heat input, the type of fuel combusted in the unit during the report year, the methodology used to calculate CO
To reduce the reporting burden, the proposed rule would allow reporting of the combined GHG emissions from multiple units at the facility instead of requiring emissions reporting for each individual unit, in certain instances. Three types of emissions aggregation would be allowed. First, the combined GHG emissions from a group (or groups) of small units at a facility could be reported, provided that the combined maximum rated heat input of the units in the group does not exceed 250 mmBtu/hr. Second, the combined GHG emissions from units in a common stack configuration could be reported, if CEMS are used to continuously monitor the CO
Different levels of verification data are required depending upon which tier is used for reporting. For Tier 1, only the total quantity of each type of fuel combusted during the report year would be reported. For Tier 2, the quantity of each type of fuel combusted during each measurement period would be reported, along with all high heat values used in the emissions calculations, the methods used to determine the HHVs, and information indicating which HHVs (if any) are substitute data values.
For Tier 3, the quantity of each type of fuel combusted during each measurement period (day or month) would be reported, along with all carbon content values and, if applicable, molecular weight measurements used in the emissions calculations, with information indicating which ones (if any) are substitute data values. In addition, the results of all fuel flow meter calibrations would be reported along with information indicating which analytical methods were used for the carbon content determinations, flow meter calibrations and (if applicable) oil tank drop measurements.
For Tier 4, the number of unit operating days and hours would be reported, along with daily CO
If MSW is combusted in the unit, the owner or operator would be required to report the results of the quarterly sample analyses used to determine the biogenic percentage of CO
Finally, for units that use acid gas scrubbing with sorbent injection but are not equipped with CEMS, the owner or operator would be required to report information on the type and amount of sorbent used.
In addition to meeting the general recordkeeping requirements in proposed 40 CFR part 98, subpart A, whenever company records are used to estimate fuel consumption (e.g., when the Tier 1 or 2 emissions calculation methodology is used) and sorbent consumption, EPA proposes to require the owner or operator to keep on file a detailed explanation of how fuel usage is quantified, including a description of the QA procedures that are used to ensure measurement accuracy (e.g., calibration of weighing devices and other instrumentation).
As discussed in Section IV of this preamble and proposed 40 CFR part 98, subpart A, there are a number of facilities that are not part of a source category listed in 40 CFR 98.2(1)(a) or (2) but have stationary combustion equipment emitting GHG emissions. In 2010, those facilities would have to determine whether or not they are subject to the requirements of this rule (i.e., if their emissions are 25,000 metric tons CO
This section of the preamble addresses GHG emissions reporting for facilities with EGUs that are in the ARP, and are subject to the CO
Electricity generating units in the ARP reported CO
If a facility includes within its boundaries at least one EGU that is subject to the ARP, the facility would be subject to the mandatory GHG emissions reporting of proposed 40 CFR part 98, subpart D. Facilities with EGUs in the ARP would not be expected to report any new CO
For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
For ARP units, the CO
As CH
The additional units at an affected facility that are not in the ARP would use the GHG calculation methods specified and required in proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
The proposed missing data substitution procedures for CH
The proposed data reporting requirements are discussed in Section V.C.5 of this preamble, under General Stationary Fuel Combustion Sources.
The records that must be retained regarding CH
Adipic acid is a white crystalline solid used in the manufacture of synthetic fibers, plastics, coatings, urethane foams, elastomers, and synthetic lubricants. Commercially, it is the most important of the aliphatic dicarboxylic acids, which are used to manufacture polyesters. Adipic acid is also used in food applications.
Adipic acid is produced through a two-stage process. The first stage usually involves the oxidation of cyclohexane to form a cyclohexanone/cyclohexanol mixture. The second stage involves oxidizing this mixture with nitric acid to produce adipic acid.
National emissions from adipic acid production were estimated to be 9.3 million metric tons CO
Process emissions from the production of adipic acid vary with the types of technologies and level of emission controls employed by a facility. DE for N
As part of this proposed rule, stationary combustion emissions would be estimated and reported according to the applicable procedures in proposed 40 CFR part 98, subpart C. For additional background information on adipic acid production, please refer to the Adipic Acid Production TSD (EPA–HQ–OAR–2008–0508–005).
In developing the threshold for adipic acid production, we considered emissions-based thresholds of 1,000 metric tons CO
Facility-level emissions estimates based on known facility capacities for the four known adipic acid facilities suggests that each of the facilities would be at least five times over the 100,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Adipic Acid Production TSD (EPA–HQ–OAR–2008–0508–005). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating adipic acid production process emissions (e.g., 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), and TRI). These methodologies coalesce around the four options discussed below.
We identified Options 3 and 4 as the approaches providing the lowest uncertainty and the best site-specific estimates based on differences in process operation and abatement technologies. Option 3 requires annual monitoring of N
Option 4 was not chosen as the required method because, while N
We request comment on the advantages and disadvantages of using Options 3 and 4. After consideration of public comments, we may promulgate one or more of these options or a combination based on the additional information that is provided.
We decided against Options 1 and 2 because facility-specific emission factors are more appropriate for reflecting differences in process design and operation. According to IPCC, the default emission factors for adipic acid are relatively certain because they are derived from the stoichiometry of the chemical reaction employed to oxidize nitric acid. However, there is still uncertainty in the amount of N
The various approaches to monitoring GHG emissions are elaborated in the Adipic Acid Production TSD (EPA–HQ–OAR–2008–0508–005).
For process sources that use Option 3 (facility-specific emission factor), no missing data procedures would apply because the facility-specific emission factor is derived from an annual performance test and used in each calculation. The emission factor would be multiplied by the production rate, which is readily available. If the test data are missing or lost, the test would have to be repeated. Therefore, 100 percent data availability would be required.
We propose that facilities submit their total annual N
Capacity, actual production, and operating hours support verification of the emissions data provided by the facility. The production rate can be determined through sales records or by direct measurement using flow meters or weigh scales. This industry generally measures the production rate as part of normal operating procedures.
A list of abatement technologies would be helpful in assessing the widespread use of abatement in the adipic acid source category, cataloging any new technologies that are being used, and documenting the amount of time that the abatement technologies are being used.
A full list of data to be reported is included in the proposed 40 CFR part 98, subparts A and E.
We propose that facilities maintain records of annual testing of N
This source category includes primary aluminum production facilities. Secondary aluminum production facilities would not be required to report emissions under Subpart F. Aluminum is a light-weight, malleable, and corrosion-resistant metal that is used in manufactured products in many sectors including transportation, packaging, building and construction. As of 2005, the U.S. was the fourth largest producer of primary aluminum, with approximately eight percent of the world total (Aluminum Production TSD
CO
In addition to CO
Another potential source of process CO
We propose to require all owners or operators of primary aluminum facilities to report the total quantities of PFC and CO
In developing the threshold for primary aluminum, we considered the emissions thresholds 1,000, 10,000, 25,000, and 100,000 metric tons CO
We propose that all primary aluminum facilities be subject to reporting. All smelters that operated in 2006 would be required to report if a 10,000, 25,000, or 100,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Aluminum Production TSD (EPA–HQ–OAR–2008–0508–006). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
This section of this preamble provides monitoring methods for calculating and reporting process CO
Protocols and guidance reviewed for this analysis include the 2006 IPCC Guidelines, EPA's Voluntary Aluminum Industrial Partnership, the Inventory of U.S. Greenhouse Gas Emissions and Sinks, the International Aluminum Institute's Aluminum Sector Greenhouse Gas Protocol, the Technical Guidelines for the Voluntary Reporting of Greenhouse Gases (1605(b)) Program, EPA's Climate Leaders Program, and TRI.
The methods described in these protocols and guidance coalesce around the methods described by the International Aluminum Institute's Aluminum Sector Greenhouse Gas Protocol and the 2006 IPCC Guidelines. These methods range from Tier 1 approaches based on aluminum production to Tier 3 approaches based primarily on smelter-specific data. The IPCC Tier 3 and International Aluminum Institute methods are essentially the same.
Both the IPCC Tier 3 method and the less accurate IPCC Tier 2 method are based on these equations and parameters. The critical distinction between the two methods is that the Tier 3 method requires smelter-specific slope coefficients while the Tier 2 method relies on default, technology-specific slope coefficients. Of the currently operating U.S. smelters, all but one has measured a smelter-specific coefficient at least once. However, as discussed below, some smelters may need to update these measurements if they occurred more than 3 years ago.
Use of the Tier 3 approach significantly improves the precision of a smelter's PFC emissions estimate. For individual facilities using the most common smelter technology in the U.S., the uncertainty (95 percent confidence interval) of estimates developed using the Tier 2 approach is ±50 percent,
During the past few years, multiple U.S. smelters have adopted changes to their production process which are likely to have changed their slope coefficients.
We understand that two smelting companies in the U.S., Rio Tinto Alcan and Alcoa, have the necessary equipment and teams in-house to measure smelter-specific slope factors. These two companies account for 11 out of 15 of the operating smelters in the U.S. The remaining facilities would need to hire a consultant to conduct a measurement study once every three years to accurately determine their slope coefficients. The cost of hiring a consultant to conduct the measurement study is probably significantly lower than the capital, labor and O&M costs of the equipment, training, and maintenance required to conduct the measurements in-house. While the cost to implement a Tier 3 approach is significantly greater than the cost to implement a Tier 2 approach, the benefit of reduced uncertainty is considerable (approximately 40 percent), as noted above.
We request comment on the proposal that all smelters be required to measure their smelter-specific slope coefficients at least once every three years. We considered, but are not proposing, to exempt “high performing” smelters, as defined by the 2006 IPCC Guidelines, from the requirement to measure their smelter-specific slope coefficients more
If your facility does not have stationary combustion, or if you do not currently have CEMS that meet the requirements outlined in proposed 40 CR part 98, subpart C, or where the CEMS would not adequately account for process CO
For prebake cells, CO
CO
The data reported by companies participating in EPA's Voluntary Aluminum Industrial Partnership has generally not included smelter-specific values for each of these variables. However, most participants in the Voluntary Aluminum Industrial Partnership have used either data on paste consumption (for Søderberg cells) or on net anode consumption (for Prebake cells), along with some smelter-specific data on impurities, to develop a hybrid IPCC Tier 2/3 estimate (i.e., combination of smelter-specific and default factors).
CO
As is the case for CO
For CO
Where anode effect minutes per cell day data points are missing, the average anode effect minutes per cell day of the remaining measurements within the same reporting period may be applied. These parameters are typically logged by the process control system as part of the operations of nearly all aluminium production facilities and the uncertainties in these data are low.
It is likely that aluminum production levels would be well known, since businesses rely on accurate monitoring and reporting of production levels. The 2006 IPCC Guidelines specify an uncertainty of less than 1 percent in the data for the annual production of aluminum. The likelihood for missing data is low.
For CO
In addition to annual GHG emissions data, facilities would be required to submit annual aluminum production and smelter technology used. The following PFC-specific information would also be required to be reported on an annual basis: Anode effect minutes per cell-day, and anode effect frequency and duration. Smelters would also be required to submit smelter-specific slope coefficient; the last date when smelter-specific slope coefficient was measured; certification that measurements of slope coefficients were conducted in accordance with the method identified in proposed 40 CFR part 98, subpart F; and the parameters used by the smelter to measure the frequency and duration of anode effects.
The following CO
These records consist of values that are used to calculate the emissions and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly.
In addition to the data reported, we propose that facilities maintain records on monthly production by smelter, anode effect minutes per cell-day or anode effect overvoltage by month, facility specific emission coefficient linked to anode effect performance, and net anode consumption for Prebake cells or paste consumption for Søderberg cells.
These records consist of data that would be used to calculate the GHG emissions and are necessary to verify that the emissions monitoring and calculations are done correctly.
Ammonia is a major industrial chemical that is mainly used as fertilizer, directly applied as anhydrous ammonia, or further processed into urea, ammonium nitrates, ammonium phosphates, and other nitrogen compounds. Ammonia also is used to produce plastics, synthetic fibers and resins, and explosives.
Ammonia can be produced through three processes: Steam reforming, solid fuel gasification, and brine electrolysis. The production of ammonia typically uses conventional steam reforming or solid fuel gasification and generates both combustion and process-related greenhouse gas emissions. The production of ammonia through the brine electrolysis process does not produce process GHG emissions, although it releases GHGs from combustion of fuels to support the electrolysis process. We have not identified any facilities in the U.S. producing ammonia through the brine electrolysis process.
Catalytic steam reforming of ammonia generates process-related CO
Not all of the CO
Some facilities produce for sale a combination of ammonia, methanol, and hydrogen. We propose that facilities report their process-related GHG emissions in the source category corresponding to the primary NAICS code for the facility. For example, a facility that primarily produces ammonia but also produces methanol would report in the ammonia manufacturing source category. Since CO
National emissions from ammonia manufacturing were estimated to be 14.6 million metric tons CO
For additional background information on ammonia manufacturing, please refer to the Ammonia Manufacturing TSD (EPA–HQ–OAR–2008–0508–007).
In developing the reporting threshold for ammonia manufacturing, we considered emissions-based thresholds of 1,000 metric tons CO
Facility-level emissions estimates based on known plant capacities suggest that all known facilities, except two, exceed the 100,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Ammonia Manufacturing TSD (EPA–HQ–OAR–2008–0508–007). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international monitoring guidelines and protocols include methodologies for estimating both combustion and process-related emissions from ammonia manufacturing (e.g., 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), and TCR). These methodologies coalesce around the following four options which we considered for quantifying emissions from ammonia manufacture:
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS does not measure CO
The proposed monitoring method is Option 3. Options 3 and 4 provide the most accurate estimates from site-specific conditions. Option 3 is consistent with current feedstock monitoring practices at facilities within this industry, thereby minimizing costs. For CO
In general, we decided against existing methodologies that relied on default emission factors or default values for carbon content of materials because the differences among facilities could not be discerned, and such default approaches are inherently inaccurate for site-specific determinations. The use of default values is more appropriate for sector-wide or national total estimates from aggregated activity data than for determining emissions from a specific facility.
The various approaches to monitoring GHG emissions are elaborated in the Ammonia Manufacturing TSD (EPA–HQ–OAR–2008–0508–007).
The proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or “missing.” For missing feedstock supply rates, use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure. There are no missing data procedures for carbon content. A re-test must be performed if the data from any monthly measurements are determined to be invalid.
We propose that facilities that estimate their process CO
We propose that each ammonia manufacturing facility maintain records of monthly carbon content analyses, and the method used to determine the quantity of feedstock used. These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly.
Hydraulic Portland cement, the primary product of the cement industry, is a fine gray or white powder produced by heating a mixture of limestone, clay, and other ingredients at high temperature. Limestone is the single largest ingredient required in the cement-making process, and most cement plants are located near large limestone deposits. CO
During the cement production process, calcium carbonate (CaCO
Additional CO
National GHG emissions from cement production were estimated to be 86.83 million metric tons CO
For additional background information on cement production, please refer to the Cement Production TSD (EPA–HQ–OAR–2008–0508–008).
In developing the threshold for cement manufacturing, we considered emissions-based thresholds of 1,000 metric tons CO
All emissions thresholds examined covered over 99.9 percent of CO
For a full discussion of the threshold analysis, please refer to the Cement Production TSD (EPA–HQ–OAR–2008–0508–008). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from cement manufacturing (e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG emissions reporting program, EPA's Climate Leaders, the EU Emissions Trading System, and the Cement Sustainability Initiative Protocol). These
Under Option 2, we propose that facilities develop facility-specific emission factors relating CO
Most current protocols propose this method, but allow facilities to apply a national default emission factor. We propose the development of a facility-specific emission factor based on the understanding that facilities analyze the carbonate contents of their raw materials to the kiln on a frequent basis, either on a daily basis or every time there is a change in the raw material mix.
In some protocols, this method requires correcting for purchases and sales of clinker, such that a facility is only accounting for emissions from the clinker that is manufactured on site. This approach provides better emissions data than protocols where the method does not correct for clinker purchases and sales. In some protocols, the method requires reporters to start with cement production, estimate the clinker fraction, and then estimate the carbonate input used to produce the clinker. Conceptually, this might not be any different than the kiln input approach as the facility would ultimately have to identify and quantify the carbonate inputs to the kiln.
The kiln input approach was considered, but not proposed, because it would not lead to significantly reduced uncertainty in the emissions estimate over the clinker based approach, where a site-specific emission factor is developed using periodic sampling of the carbonate mix into the kiln. The primary difference is the proposed clinker-based approach requires a monthly analysis of the degree of calcination achieved in the clinker in order to develop the facility-specific emissions factor, whereas the kiln input approach would require monthly monitoring of the inputs and outputs of the kiln. We concluded that although the kiln input does not improve certainty estimates significantly, it could potentially be more costly depending on the carbonate input sampling frequency.
Early domestic and international guidance documents for estimating process CO
The various approaches to monitoring GHG emissions are elaborated in the Cement Production TSD (EPA–HQ–OAR–2008–0508–008).
For facilities with CEMs, we propose that facilities follow the missing data procedures in proposed 40 CFR part 98, subpart C, which are also discussed in Section V.C of this preamble.
For facilities without CEMs, we propose that no missing data procedures would apply because the emission
We propose that facilities submit annual CO
In addition to the data reported, we propose that facilities using the clinker-based approach to calculate emissions keep records of monthly carbonate consumption, monthly cement production, monthly clinker production, results from monthly chemical analysis of carbonates, documentation of calculated site specific clinker emission factor, quarterly cement kiln dust production, total annual fraction calcination achieved, organic carbon content of the raw material, and the amount of raw material consumed annually. These records include values directly used to calculate the reported emissions; and these records are necessary to verify the estimated GHG emissions. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and H.
The electronics industry uses multiple long-lived fluorinated GHGs such as PFCs, HFCs, SF
The fluorinated gases (at room temperature) are used for plasma etching of silicon materials and cleaning deposition tool chambers. Additionally, semiconductor manufacturing employs fluorinated GHGs (typically liquids at room temperature) as heat transfer fluids. The most common fluorinated GHGs in use are HFC–23, CF
Electronics manufacturers may also use N
The etching process uses plasma-generated fluorine atoms, which chemically react with exposed dielectric film to selectively remove the desired portions of the film. The material removed as well as undissociated fluorinated gases flow into waste streams and, unless emission control systems are employed, into the atmosphere.
Chambers used for depositing dielectric films are cleaned periodically using fluorinated and other gases. During the cleaning cycle the gas is converted to fluorine atoms in plasma, which etches away residual material from chamber walls, electrodes, and chamber hardware. Undissociated fluorinated gases and other products pass from the chamber to waste streams and, unless emission control systems are employed, into the atmosphere.
In addition to emissions of unreacted gases, some fluorinated compounds can also be transformed in the plasma processes into different fluorinated GHGs which are then exhausted, unless abated, into the atmosphere. For example, when C
Fluorinated GHG liquids (at room temperature) such as fully fluorinated linear, branched or cyclic alkanes, ethers, tertiary amines and aminoethers, and mixtures thereof are used as heat transfer fluids at several semiconductor facilities to cool process equipment, control temperature during device testing, and solder semiconductor devices to circuit boards. The fluorinated heat transfer fluid's high vapor pressures can lead to evaporative losses during use.
(1) Plasma etching;
(2) Chamber cleaning;
(3) Chemical vapor deposition using N
(4) Heat transfer fluid use.
Our understanding is that only semiconductor facilities use heat transfer fluids; we request comment on this assumption.
For additional background information on the electronics industry, refer to the Electronics Manufacturing TSD (EPA–HQ–OAR–2008–0508–009).
For manufacture of semiconductors, LCDs, and MEMs, we are proposing capacity-based thresholds equivalent to an annual emissions threshold of 25,000 metric tons CO
We are seeking comment on the inclusion of LEDs, disk readers and other products in the electronics manufacturing source category. Given that the manufacturing process for these devices is similar to other electronics, we are specifically interested in seeking feedback on the level of emissions from their manufacturer and whether subjecting these products to an emissions threshold of 25,000 metric ton CO
In our analysis, we considered emission thresholds of 1,000 metric tons CO
We selected the 25,000 metric tons CO
We propose to use a production-based threshold based on the rated capacities of facilities, as opposed to an emissions-based threshold, where possible, because it simplifies the applicability determination. Therefore, we derived production capacity thresholds that are approximately equivalent to metric tons CO
The proposed capacity-based thresholds are estimated to cover about 50 percent of semiconductor facilities and between 0 percent and 20 percent of the facilities manufacturing MEMs and LCDs. At the same time, the thresholds are expected to cover nearly 96 percent of fluorinated GHG emissions from semiconductor facilities, and 0 percent and 66 percent of fluorinated GHG emissions from facilities manufacturing LCDs and MEMs, respectively. Combined these emissions are estimated to account for close to 94 percent of fluorinated GHG emissions from electronics as a whole.
We are proposing capacity-based thresholds for the electronics industry, where possible, because electronics manufacturers may employ emissions control equipment (e.g., thermal oxidizers, fluorinated GHG capture recycle systems) to lower their fluorinated GHG emissions. In addition, capacity-based thresholds would permit facilities to quickly determine whether or not they must report under this rule.
When abatement equipment is used, electronics manufacturers often estimate their emissions using the manufacturer-published DRE for the equipment. However, abatement equipment may fail to achieve its rated DRE either because it is not being properly operated and maintained or because the DRE itself was incorrectly measured due to a failure to account for the effects of dilution. (For example, CF
For additional background information on the threshold analysis, refer to the Electronics Manufacturing TSD (EPA–HQ–OAR–2008–0508–009). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Under the proposed rule, we estimate that 17 percent of all semiconductor manufacturing facilities would be required to report using an IPCC Tier 3 approach (equivalent to 29 facilities out of 175 total facilities) and that 56 percent of total semiconductor emissions (equivalent 3.4 million metric tons CO
Information on gas consumption by process is often gathered as business as usual,
The guidance prepared by International SEMATECH Technology Transfer #0612485A–ENG (December 2006) must be followed when preparing gas utilization and by-product formation measurements. We have determined that electronics manufacturers commonly track fluorinated GHG consumption using flow metering systems calibrated to ±1 percent or better accuracy. Thus the equation for estimating emissions does not account for cylinder heels. However, a facility may choose to estimate consumption by weighing fluorinated GHG cylinders when placed into and taken out of service, as is common practice by the magnesium industry.
The use of the IPCC Tier 3 method and standard site-specific DRE measurement would provide the most certain and practical emission estimates for large facilities. The uncertainty associated with an IPCC Tier 3 approach is lower than any of the other IPCC approaches, and is on the order of ±30 percent at the 95 percent confidence interval. We estimate that the Tier 3 approach would not impose a significant burden on facilities because large semiconductor facilities are already using Tier 3 methods and/or have the necessary data to do so readily available, as noted above.
The Tier 2b approach does not account for variation among individual processes or tools and, therefore, the estimated emissions have an uncertainty about twice as high as that of IPCC Tier 3 estimates. However, we have concluded that the IPCC Tier 3 method would be unduly burdensome to the estimated 146 facilities with annual production less than 10,500 m
The first method would require facilities (or their equipment suppliers) to test the DRE of the equipment using an industry standard protocol, such as the one under development by EPA as part of the
We believe that the proposed DRE measurement method is generally robust, but we are requesting comment on one aspect of that method. We are concerned that the DREs measured and calculated for CF
Facilities pursuing either DRE verification method would also be required to use the equipment within the manufacturer's specified equipment lifetime, operate the equipment within manufacturer specified limits for the gas mix and exhaust flow rate intended for fluorinated GHG destruction, and maintain the equipment according to the manufacturer's guidelines. We request comment on these proposed requirements.
We propose that electronics manufacturers use the IPCC Tier 2 approach, which is a mass-balance approach, to estimate the emissions of each fluorinated heat transfer fluid. The IPCC Tier 2 approach uses company-specific data and accounts for differences among facilities' heat transfer fluids (which vary in their GWPs), leak rates, and service practices. It has an uncertainty on the order of ±20 percent at the 95 percent confidence interval according to the 2006 IPCC Guidelines. The Tier 2 approach is preferable to the IPCC Tier 1 approach, which relies on a default emissions factor to estimate heat transfer fluid emissions and has relatively high uncertainty compared to the Tier 2 approach.
We reviewed the PFC Reduction/Climate Partnership for the Semiconductor Industry, U.S. GHG Inventory, 1605(b), EPA Climate Leaders, WRI, TRI, and the World Semiconductor Council methods for estimating etching and cleaning emissions. All of the methods draw from both the 2000 and 2006 IPCC Guidelines.
The Tier 1 approach is based on the surface area of substrate (e.g., silicon, LCD or PV-cell) produced during manufacture multiplied by a default gas-specific emission factor. The advantages of the Tier 1 approach lie in its simplicity. However, this method does not account for the differences among process types (i.e., etching versus cleaning), individual processes, or tools, leading to uncertainties in the default emission factors of up to 200 percent at the 95 percent confidence interval.
The Tier 2a approach is based on the gas consumption multiplied by default factors for utilization, by-product formation, and destruction. The Tier 2a approach is relatively simple, given that gas consumption data is collected as part of business as usual. However, due to variation in gas utilization between etching and cleaning processes, the estimated emissions using Tier 2a have greater uncertainty than Tier 2b estimated emissions.
Tier 2b/3 hybrid approach involves requiring Tier 3 reporting for all facilities, but only for the top three gases emitted at each facility. For all other gases, the Tier 2b approach would be required. The top three gases emitted, based on data in the Inventory of U.S. GHG Emissions and Sinks, are C
We did not select the Tier 1 and Tier 2a methods due to the greater uncertainty inherent in these approaches. Although the Tier 2b/3 hybrid approach would provide more accurate emissions estimates for small facilities, we concluded that the Tier 2b method with site-specific DRE measurements would provide sufficient accuracy without the additional monitoring and recordkeeping requirements of the Tier 3 method.
We propose collecting emissions data from MEMS manufacturers meeting the threshold criterion although no IPCC default emission factors exist for MEMs and the IPCC emission factors for semiconductor and LCD manufacturing may not be reliable for MEMs. Therefore, we are seeking information on emissions and emission factors for both MEMs and LCD manufacturing.
Where facility-specific process gas utilization rates and by-product gas formation rates are missing, facilities can estimate etching/cleaning emissions by applying defaults from the next lower Tier (e.g., IPCC Tier 2b or Tier 2a) to estimate missing data. However, facilities must limit their use of defaults from the next lower Tier to less than 5 percent of their emissions estimate.
Default values for estimating DRE would not be permitted. DRE values must be estimated as zero in the absence of facility-specific DREs that have been measured using a standard protocol. Gas consumption is collected as business as usual and is not expected to be missing; therefore, it would not be permitted to revert to the Tier 1 approach for estimating emissions. When estimating heat transfer fluid emissions during semiconductor manufacture, the use of the mass-balance approach requires correct records for all inputs. Should the facility be missing records for a given input, it may be possible that the heat transfer fluid supplier has information in their records for the facility.
Owners and operators would be required to report GHG emissions for the facility, for all plasma etching processes, all chamber cleaning, all chemical vapor deposition processes, and all heat tranfer fluid use. Along with their emissions, facilities would be required to report the following: Method used (i.e., 2b or 3), mass of each gas fed into each process type, production capacity in terms of substrate surface area (e.g., silicon, PV-cell, LCD), factors used for gas utilization, by-product formation and their sources/uncertainties, emission control technology DREs and their uncertainties, fraction of gas fed into each process type with emissions, control technologies, description of abatement controls, inputs in the mass-balance equation (for heat transfer fluid emissions), example calculation, and emissions uncertainty estimate.
These data form the basis of the calculations and are needed for us to understand the emissions data and verify the reasonableness of the reported emissions.
We propose that facilities keep records of the following: Data actually used to estimate emissions, records supporting values used to estimate emissions, the initial and any subsequent tests of the DRE of oxidizers, the initial and any subsequent tests to determine emission factors for process, and abatement device calibration/maintenance records.
These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations are done correctly.
Ethanol is produced primarily for use as a fuel component, but is also used in industrial applications and in the manufacture of beverage alcohol. Ethanol can be produced from the fermentation of sugar, starch, grain, and cellulosic biomass feedstocks, or produced synthetically from ethylene or hydrogen and carbon monoxide.
The sources of GHG emissions at ethanol production facilities that must be reported under the proposed rule are stationary fuel combustion, onsite landfills, and onsite wastewater treatment.
Proposed requirements for stationary fuel combustion emissions are set forth in proposed 40 CFR part 98, subpart C.
Proposed requirements for landfill emissions are set forth in Section V.HH of this preamble. Data is unavailable on landfilling at ethanol facilities, but it is our understanding that some of these facilities may have landfills with significant CH
The wastewater generated at ethanol production facilities is handled in a variety of ways, with dry milling and wet milling facilities generally treating wastewaters differently. In 2006, CH
As noted in Section IV.B of this preamble under the heading “Reporting by fuel and industrial gas suppliers”, ethanol producers and other suppliers of biomass-based fuel are not required to report GHG emissions from their products under this proposal, and we seek comment on this approach.
The proposed threshold for reporting emissions from ethanol production facilities is 25,000 metric tons CO
Data were unavailable to estimate emissions from landfills at ethanol refineries, or to estimate the combined wastewater treatment and stationary fuel combustion emissions at facilities. Data on stationary fuel combustion were used to estimate the minimum number of facilities that would meet each of the facility-level thresholds examined. The
For more information on this analysis, please refer to the Ethanol Production TSD (EPA–HQ–OAR–2008–0508–010). EPA is seeking comment on the analysis and on alternative data sources for stationary combustion at ethanol production facilities. For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Refer to Sections V.C, V.HH, and V.II of this preamble for monitoring methods for general stationary fuel combustion sources, landfills, and wastewater treatment occurring on-site at ethanol production facilities.
Refer to Sections V.C, V.HH, and V.II of this preamble for procedures for estimating missing data for general stationary fuel combustion sources, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities.
Refer to Sections V.C, V.HH, and V.II of this preamble for reporting requirements for general stationary fuel combustion sources, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities. In addition, you would be required to report the quantity of CO
Refer to Sections V.C, V.HH, and V.GG of this preamble for recordkeeping requirements for stationary fuel combustion, landfills, and industrial wastewater treatment occurring on-site at ethanol production facilities.
A ferroalloy is an alloy of iron with at least one other metal such as chromium, silicon, molybdenum, manganese, or titanium. For this proposed rule, we are defining the ferroalloy production source category to consist of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal. Ferroalloys are used extensively in the iron and steel industry to impart distinctive qualities to stainless and other specialty steels, and serve important functions during iron and steel production cycles. Silicon metal is included in the ferroalloy metals category due to the similarities between its production process and that of ferrosilicon. Silicon metal is used in alloys of aluminum and in the chemical industry as a raw material in silicon-based chemical manufacturing.
The basic process used at U.S. ferroalloy production facilities is a batch process in which a measured mixture of metals, carbonaceous reducing agents, and slag forming materials are melted and reduced in an electric arc furnace. The carbonaceous reducing agents typically used are coke or coal. Molten alloy tapped from the electric arc furnace is casted into solid alloy slabs which are further mechanically processed for sale as product or disposed in landfills.
Ferroalloy production results in both combustion and process-related GHG emissions. The major source of GHG emissions from a ferroalloy production facility are the process-related emissions from the electric arc furnace operations. These emissions, which consist primarily of CO
Total nationwide GHG emissions from ferroalloy production facilities operating in the U.S. were estimated to be approximately 2.3 million metric tons CO
Additional background information about GHG emissions from the ferroalloy production source category is available in the Ferroalloy Production TSD (EPA–HQ–OAR–2008–0508–011).
Ferroalloy production facilities in the U.S. vary in the specific types of alloy products produced. In developing the threshold for ferroalloy production facilities, we considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO
Table K–1 of this preamble shows that all nine of the facilities would be required to report emissions at all thresholds except 100,000 metric tons CO
We reviewed existing methodologies used by the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program, the Australian National Greenhouse Gas Reporting Program, and EU Emissions Trading System. In general, the methodologies used for estimating process related GHG emissions at the facility level coalesce around the following four options.
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where CEMS would not adequately account for process emissions, the proposed monitoring method is Option 2. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO
Given the variability of the alloy products produced and carbonaceous reducing agents used at U.S. ferroalloy production facilities, we concluded that using facility-specific information under Option 2 is preferred for estimating CO
Emissions data collected under Option 3 would have the lowest uncertainty, expected to be less than 5 percent. For Option 2, the material-specific emission factors would be expected to be within 10 percent, which would provide less uncertainty overall than for Option 1, which may have uncertainty of 25 to 50 percent. The use of the default CO
In comparison to the CO
We also decided against Option 3 because of the potential for significant variations at ferroalloy production facilities in the characteristics and quantities of the electric arc furnace inputs (e.g., metal ores, carbonaceous reducing agents) and process operating parameters. A method using periodic, short-term stack testing would not be practical or appropriate for those ferroalloy production facilities where the electric arc furnace inputs and operating parameters do not remain relatively consistent over the reporting period.
The various approaches to monitoring GHG emissions are elaborated in the Ferroalloy Production TSD (EPA–HQ–OAR–2008–0508–011).
In cases when an owner or operator calculates CO
The proposed rule would require reporting of the total annual CO
Maintaining records of the information used to determine the reported GHG emissions are necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. We propose that all affected facilities maintain records of product production quantities, and number of facility operating hours each month. If you use the carbon balance procedure, you would record for each carbon-containing input material consumed or used and output material produced the monthly material quantity, monthly average carbon content determined for material, and records of the supplier provided information or analyses used for the determination. If you use the CEMS procedure, you would maintain the CEMS measurement records.
This source category covers emissions of fluorinated GHGs that occur during the production of HFCs, PFCs, SF
Emissions can occur from leaks at flanges and connections in the production line, during separation of byproducts and products, during occasional service work on the production equipment, and during the filling of tanks or other containers that are distributed by the producer (e.g., on trucks and railcars). Fluorinated GHG emissions from U.S. facilities producing fluorinated GHGs are estimated to range from 0.8 percent to 2 percent of the amount of fluorinated GHGs produced, depending on the facility.
In 2006, 12 U.S. facilities produced over 350 million metric tons CO
The production of fluorinated gases causes both combustion and fluorinated GHG emissions. Fluorinated GHG production facilities would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO
We propose that owners and operators of facilities estimate and report fluorinated GHG and combustion emissions if those emissions together exceed 25,000 metric tons CO
In developing the threshold, we considered emissions thresholds of 1,000 metric tons CO
As can be seen from the tables, most HFC, PFC, SF
EPA requests comment on whether it should adopt a capacity-based threshold for this sector, and if so, what fluorinated GHG and combustion-related emission rates should be used to develop this threshold. Where EPA has reasonably good information on the relationship between production capacity and emissions, and where this relationship does not vary excessively from facility to facility, EPA is generally proposing capacity-based thresholds to make it easy for facilities to determine whether or not they must report. In this case, however, EPA has little data on combustion emissions and their likely magnitude compared to fluorinated GHG emissions from this source.
As noted above, the capacity thresholds in Table L–1 of this preamble were developed based on a fluorinated GHG emission rate of 2 percent of production. While EPA believes that this emission rate is an upper-bound for fluorinated GHGs, neither the rate nor the thresholds account for combustion-related emissions. Thus, it is possible that the production capacities listed in Table L–1 of this preamble are inappropriately high.
In the event that a capacity-based threshold were adopted, facilities would be required to multiply the production capacity of each production line by the GWP of the fluorinated GHG produced on that line. Facilities would then be required to sum the resulting CO
A full discussion of the threshold selection analysis is available in the Fluorinated GHG Production TSD (EPA–HQ–OAR–2008–0508–012). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
In developing this proposed rule, we reviewed a number of protocols for estimating fluorinated GHG emissions from fluorocarbon production, such as the 2006 IPCC Guidelines. In general, these protocols present three methods. In the first approach, a default emission factor is applied to the total production of the plant. In the second approach, fluorinated GHG emissions are equated to the difference between the mass of reactants fed into the process and the sum of the masses of the main product and those of any by-products and/or wastes. In the third approach, the composition and mass flow rate of the gas streams actually vented to the atmosphere are monitored either continuously or during a period long enough to establish an emission factor.
If you produce fluorinated GHGs, we are proposing that you monitor fluorinated GHG emissions using the second approach, known as the mass-balance or yield approach. There are two variants of the mass-balance approach. In the first variant, only some of the reactants and products, including the fluorinated GHG product, are considered. In the second variant, all of the reactants, products, and by-products are considered. Both variants are discussed in more detail in the Fluorinated GHG Production TSD (EPA–HQ–OAR–2008–0508–012).
We are proposing that you monitor emissions using the first variant. In this approach, you would calculate the difference between the expected production of each fluorinated GHG based on the consumption of reactants and the measured production of that fluorinated GHG, accounting for yield losses related to byproducts (including intermediates permanently removed from the process) and wastes. Yield losses that could not be accounted for would be attributed to emissions of the fluorinated GHG product. This calculation would be performed for each reactant, and estimated emissions of the fluorinated GHG product would be equated to the average of the results obtained for each reactant. If fluorinated GHG byproducts were produced and were not completely recaptured or completely destroyed, you would also estimate emissions of each fluorinated GHG byproduct.
To carry out this approach, you would daily weigh or meter each reactant fed into the process, the primary fluorinated GHG produced by the process, any reactants permanently removed from the
In general, we understand that production facilities already perform these measurements and calculations to the proposed level of accuracy and precision in order to monitor their processes and yields. However, we request comment on this issue. We specifically request comment on the proposed scope and frequency of process stream concentration measurements. As noted above, concentration measurements would be triggered when products or byproducts occur in more than trace concentrations with other components in process streams (which include waste streams). However, it is possible that products or byproducts could occur in more than trace concentrations but still result in negligible yield losses (e.g., less than 0.2 percent). In this case, ignoring these losses may not significantly affect the accuracy of the overall GHG emission estimate. (This issue is discussed in more detail in the Fluorinated GHG Production TSD (EPA–HQ–OAR–2008–0508–012).) Similarly, decreasing the frequency of stream sampling may not have a significant impact on accuracy or precision if previous monitoring has shown that the concentrations of products and byproducts in process streams are stable or vary in a predictable and quantifiable way (e.g., seasonally due to differences in condenser cooling water temperature).
EPA recognizes that the proposed mass-balance approach would assume that all yield losses that are not accounted for are attributable to emissions of the fluorinated GHG product. In some cases, the losses may be untracked emissions or other losses of reactants or fluorinated by-products. In general, EPA understands that reactant flows are measured at the inlet to the reactor; thus, any losses of reactant that occur between the point of measurement and the reactor are likely to be small. However, reactants that are recovered from the process, whether they are recycled back into it or removed permanently, may experience some losses that the proposed method does not account for. EPA requests comment on the extent to which such losses occur, and how these might be measured.
Fluorocarbon by-products, according to the IPCC Guidelines, generally have “radiative forcing properties similar to those of the desired fluorochemical.” If this is always the case (with the exception of HFC–23 generated during production of HCFC–22, which is addressed in Section V.O of this preamble), then assuming by-product emissions are product emissions would not lead to large errors in estimating overall fluorinated GHG emissions. If the GWPs of emitted fluorinated by-products are sometimes significantly different from those of the fluorinated GHG product, and if the quantity of by-product emitted can be estimated (e.g., based on periodic or past sampling of process streams), then the quantity of emitted product could be adjusted to reflect this. EPA requests comment on whether it is necessary or practical to distinguish between emissions of fluorinated GHG products and emissions of fluorinated by-products, and if so, on the best approach for doing so.
We also request comment on the proposed accuracy and precision requirements for flowmeters and scales. If a waste or by-product stream is significantly smaller than the reactant and product streams, a less precise measurement of this stream (e.g., 0.5 percent) may not have a large impact on the precision of the fluorinated GHG emission estimate and may therefore be acceptable. Similarly, if a measurement is repeated multiple times over the course of the reporting period, the precision of individual measurements could be relaxed without seriously compromising the precision of the monthly or annual estimates. One way of adding flexibility to the precision requirements would be to require that the error of the fluorinated GHG emissions estimate be no greater than some fraction of the yield, e.g., 0.3 percent, on a monthly basis. Facilities could achieve this level of precision however they chose. We request comment on this issue and on the accuracy, precision, and cost of the proposed approach as a whole.
Analysis of Alternative Methods. EPA is not proposing the approach using the default emission factor. While this approach is simple, it is also highly imprecise; emissions in U.S. plants are estimated to vary from 0.8 percent to 2 percent of production, more than a factor of two.
EPA is not proposing the second variant of the mass-balance approach. This variant is implemented by comparing the total mass of reactants to the total mass of monitored products and byproducts, without regard for chemical identity. The drawbacks of this variant are that it is not the method currently used by facilities to track their production, and it would count losses of non-GHG products (e.g., HCl) as GHG emissions. EPA requests comment on this understanding and on the potential usefulness and accuracy of the second variant of the mass-balance approach for estimating fluorinated GHG emissions.
EPA is not proposing the third approach because it is our understanding that facilities do not routinely monitor their process vents, and therefore such monitoring is likely to be more expensive than the proposed mass-balance approach. However, the cost of monitoring may not be prohibitive, particularly if it is performed for a relatively short period of time for the purpose of developing an emission factor, similar to the approach for estimating smelter-specific slope coefficients for aluminum production.
For completeness, monitoring of process vents would need to be supplemented by monitoring of equipment leaks, whose emissions would not occur through process vents. To capture emissions from equipment leaks, we could require use of EPA Method 21 and the
We request comment on the accuracies and costs of the approaches in the
In addition, we request comment on whether we should require the vent monitoring approach, what sensitivity and precision would be appropriate for the vent concentration measurements, and on the increase in cost and improvements in accuracy and precision that would be associated with this approach relative to the proposed approach.
Emissions from Evacuation of Returned Containers. We request comment on whether you should be required to measure and report fluorinated GHG emissions associated with the evacuation of cylinders or other containers that are returned to the facility containing either residual GHGs (heels) or GHGs that would be reclaimed or destroyed. We are not proposing to require reporting of these emissions because they are not associated with new production; instead, they are downstream emissions associated with earlier production.
Nevertheless, according to the 2006 IPCC Guidelines, the overall emission rate of a production facility can increase by nearly an order of magnitude (up to 8 percent) if the residual GHG remaining in the cylinders is vented to the atmosphere. One method of tracking such emissions would be to subtract the quantities of GHG reclaimed (purified) and sold or otherwise sent back to users from the quantities of residual and used GHGs returned to the facility in cylinders by users. This approach would be similar to the mass-balance approach proposed for estimating SF
In the event that a scale or flowmeter normally used to measure reactants, products, by-products, or wastes fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, we are proposing that facilities be required to estimate these quantities using other measurements where these data are available. For example, facilities that ordinarily measure production by metering the flow into the day tank could use the weight of product charged into shipping containers for sale and distribution as a substitute. It is our understanding that the types of flowmeters and scales used to measure fluorocarbon production (e.g., Coriolis meters) are generally quite reliable, and therefore that it should rarely be necessary to rely solely on secondary production measurements. In general, production facilities rely on accurate monitoring and reporting of the inputs and outputs of the production process.
If concentration measurements are unavailable for some period, we are proposing that the facility use the average of the concentration measurements from just before and just after the period of missing data.
There is one proposed exception to these requirements: If either method would result in a significant under- or overestimate of the missing parameter, then the facility would be required to develop an alternative estimate of the parameter and explain why and how it developed that estimate.
We request comment on these proposed methods for estimating missing data.
Under the proposed rule, owners and operators of facilities producing fluorinated GHGs would be required to report both their fluorinated GHG emissions and the quantities used to estimate them, including the masses of the reactants, products, by-products, and wastes, and, if applicable, the quantities of any product in the by-products and/or wastes (if that product is emitted at the facility). We are proposing that owners and operators report annual totals of these quantities.
Where fluorinated GHG production facilities have estimated missing data, you would be required to report the reason the data were missing, the length of time the data were missing, the method used to estimate the missing
We propose that facilities report these data because the data are necessary to verify facilities' calculations of fluorinated GHG emissions. We request comment on these proposed reporting requirements.
Under the proposed rule, owners and operators of facilities producing fluorinated GHGs would be required to retain records documenting the data reported, including records of daily and monthly mass-balance calculations and calibration records for flowmeters, scales, and gas chromatographs. These records are necessary to verify that the GHG emissions monitoring and calculations were performed correctly.
Food processing facilities prepare raw ingredients for consumption by animals or humans. Many facilities in the meat and poultry, and fruit, vegetable, and juice processing industries have on-site wastewater treatment. This can include the use of anaerobic and aerobic lagoons, screening, fat traps and dissolved air flotation. These facilities can also include onsite landfills for waste disposal. In 2006, CH
Proposed requirements for stationary fuel combustion emissions are set forth in proposed 40 CFR part 98, subpart C.
Wastewater GHG emissions are described and considered in Section V.II of this preamble. For more information on wastewater treatment at food processing facilities, please refer to the Food Processing TSD (EPA–HQ–OAR–2008–0508–013).
Landfill GHG emissions are described and considered in Section V.HH of this preamble. For more information on landfills at food processing facilities, please refer to the Landfills TSD (EPA–HQ–OAR–2008–0508–034).
The sources of GHG emissions at food processing facilities that must be reported under the proposed rule are stationary fuel combustion, onsite landfills and onsite wastewater treatment.
We considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO
Data were unavailable at the time of this analysis to estimate stationary combustion emissions onsite, or the co-location of landfills and wastewater treatment at food processing faculties. Facility coverage based on onsite wastewater GHG emissions and landfill GHG emissions was estimated as described in the Wastewater Treatment TSD and Landfills TSD (EPA–HQ–OAR–2008–0508–035) and (EPA–HQ–OAR–2008–0508–034). We estimate that at the 25,000 metric tons CO
For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Refer to Sections V.C, V.HH, and V.II of this preamble for monitoring methods for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food production facilities.
Refer to Sections V.C, V.HH, and V.II of this preamble for procedures for estimating missing data for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities.
Refer to Sections V.C, V.HH, and V.II of this preamble for reporting requirements for general stationary fuel combustion, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities. In addition, you would be required to report the quantity of CO
Refer to Sections V.C, V.HH, and V.II of this preamble for recordkeeping requirements for general stationary fuel combustion sources, landfills, and wastewater treatment, respectively, occurring on-site at food processing facilities.
Glass is a common commercial item that is produced by melting a mixture of
Glass can be produced using a variety of raw material formulations. Most commercial glass is made using a soda-lime glass formulation, which consists of silica (SiO
Major carbonates used in the production of glass are limestone (CaCO
National emissions from glass manufacturing were estimated to be 4.43 million metric tons CO
For additional background information on glass manufacturing, refer to the Glass Manufacturing TSD (EPA–HQ–OAR–2008–0508–014).
In developing the threshold for glass manufacturing, we considered an emissions-based threshold of 1,000 metric tons CO
The glass manufacturing industry is heterogeneous in terms of the types of facilities. There are some relatively large, emissions-intensive facilities, but small artisan shops are common as well. For example, at a 1,000 metric tons CO
The proposed threshold for reporting emissions from glass manufacturing is 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Glass Manufacturing TSD (EPA–HQ–OAR–2008–0508–014). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many of the domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related CO
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, the proposed monitoring method would require estimating combustion emissions and process emissions separately. For combustion emissions, you would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO
To estimate process CO
The proposed rule distinguishes between carbonate-based minerals and carbonate-based raw materials used in glass production. Carbonate-based raw materials are fired in the furnace during glass manufacturing. These raw materials are typically limestone, which is primarily CaCO
In order to assess the composition of the carbonate input, we propose that facilities use data from the raw material supplier to determine the carbonate-based mineral mass fraction of the carbonate-based raw materials charged to an affected glass melting furnace. As an alternative to using data provided by the supplier, facilities can assume a value of 1.0 for the mass fraction of the carbonate-based mineral in the carbonate-based raw material. We also propose that emissions are estimated under the assumption that 100 percent of the carbon in the carbonate-based raw materials is volatilized and released from the furnace as CO
Using values of 1.0 for the carbonate-based mineral mass fractions is based on the assumption that the raw materials consist of 100 percent of the respective carbonate-based mineral (i.e., the limestone charged to the furnace consists of 100 percent CaCO
We have concluded that the carbonate input method specified in the proposed option is more certain as it involves measuring the consumption of each carbonate material charged to a glass melting furnace. According to the 2006 IPCC Guidelines, the uncertainty involved in the proposed carbonate input approach is 1 to 3 percent; in contrast, the uncertainty with using the default emission factor and cullet ratio for the production-based approach is 60 percent.
We considered use of a CO
We also considered, but decided not to propose, the production-based default emission factor-based approach referenced above for quantifying process-related CO
As part of normal business practices, glass manufacturing plants maintain the records that would be needed to calculate emissions under the proposed option. Given the greater accuracy associated with the input method and the minimal additional burden, we have determined that this requirement would not add additional burden to current practices at the facility, while providing accurate estimates of process-based CO
The various approaches to monitoring GHG emissions are elaborated in the Glass Manufacturing TSD (EPA–HQ–OAR–2008–0508–014).
To estimate process emissions of CO
For missing data on carbonate-based mineral mass fractions, we propose requiring facilities to assume that the mass fraction of each carbonate-based mineral in the carbonate-based raw materials is 1.0. This assumption may result in a slight overestimate of emissions, but should still provide a reasonably accurate estimate of emissions for the period with missing data.
We propose that facilities report total annual emissions of CO
A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and N.
In addition to the data to be reported, we propose that facilities retain monthly records of the data used to calculate GHG emissions. This would include records of the amounts of each carbonate-based raw material charged to a continuous glass melting furnace and glass production (by type). This requirement would be consistent with current business practices and the reporting requirements for emissions of other pollutants for the glass manufacturing industry.
The proposed rule also would require facilities to retain the results of all tests used to determine carbonate-based mineral mass fractions, as well as any other supporting information used in the calculation of GHG emissions. These data are directly used to calculate emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were performed correctly.
A full list of records that must be retained on site is included in proposed 40 CFR part 98, subparts A and N.
This source category includes the generation, emissions, sales, and destruction of HFC–23. The source category includes facilities that produce HCFC–22, generating HFC–23 in the process. This source category also includes facilities that destroy HFC–23, which are sometimes, but not always, also facilities that produce HCFC–22.
HFC–23 is generated during the production of HCFC–22. HCFC–22 is primarily employed in refrigeration and A/C systems and as a chemical feedstock for manufacturing synthetic polymers. Because HCFC–22 depletes stratospheric O
HCFC–22 is produced by the reaction of chloroform (CHCl
2006 U.S. emissions of HFC–23 from HCFC–22 production were estimated to be 13.8 million metric tons CO
The production of HCFC–22 and destruction of HFC–23 causes both combustion and HFC–23 emissions. HCFC–22 production and HFC–23 destruction facilities are required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO
For additional background information on HCFC–22 production, please refer to the HCFC–22 Production and HFC–23 Destruction TSD (EPA–HQ–OAR–2008–0508–015).
We propose that all facilities producing HCFC–22 be required to report under this rule. Facilities destroying HFC–23 but not producing HCFC–22 would be required to report if they destroyed more than 25,000 metric tons CO
For HCFC–22 production facilities, we considered emission-based thresholds of 1,000 metric tons CO
Our analysis showed that all of the facilities, which have capacities ranging from 18,000 to 100,000 metric tons of HCFC–22, exceeded all of the capacity-based thresholds by wide margins. The smallest plant exceeded the largest capacity-based threshold by a factor of 85.
We are not presenting a table for emission-based thresholds because we do not have facility-specific emissions information. (Under the voluntary emission reduction agreement, total emissions from the three facilities are aggregated by a third party, who submits only the total to us.) Since two of the three facilities destroy or capture most or all of their HFC–23 by-product, one or both of them probably have emissions below at least some of the emission-based thresholds discussed above. However, if the thermal oxidizers malfunctioned, were not operated properly, or were unused for some other reason, emissions of HFC–23 from each of the plants could easily exceed all thresholds. Reporting is therefore important both for tracking the considerable emissions of facilities that do not use thermal oxidation and for verifying the performance of thermal oxidation where it is used. For this reason, we propose that all HCFC–22 manufacturers report their HFC–23 emissions.
We are aware of one facility that destroys HFC–23 but does not produce HCFC–22. Although we do not know the precise quantity of HFC–23 destroyed by this facility, the Agency has concluded that the facility destroys a substantial share of the HFC–23 generated by the largest HCFC–22 production facility in the U.S. If the destruction facility destroys even one percent of this HFC–23, it is likely to destroy considerably more than the proposed threshold of 25,000 metric tons CO
For additional background information on the threshold analysis for HCFC–22 production, please refer to the HCFC–22 Production and HFC–23 Destruction TSD (EPA–HQ–OAR–2008–0508–015). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
In developing these proposed requirements, we reviewed several protocols and guidance documents, including the 2006 IPCC Guidelines, guidance developed under our voluntary program for HCFC–22 manufacturers, the WRI/WBCSD protocols, the TRI, the TSCA Inventory Update Rule, The DOE 1605(b) Voluntary Reporting Program, EPA Climate Leaders, and TRI.
We also considered the findings and conclusions of a recent report that closely reviewed the methods that facilities use to estimate and assure the quality of their estimates of HCFC–22 production and HFC–23 emissions. As noted above, the production facilities currently estimate and report these quantities to us (across all three plants) under a voluntary agreement. The report, by RTI International, is entitled “Verification of Emission Estimates of HFC–23 from the Production of HCFC–22: Emissions from 1990 through 2006” and is available in the docket for this rulemaking.
The 2008 Verification Report found that the estimation methods used by the three HCFC–22 facilities currently operating in the U.S. were all equivalent to IPCC Tier 3 methods. Under the Tier 3 methodology, facility-specific emissions are estimated based on direct measurement of the HFC–23 concentration and the flow rate of the streams, accounting for the use of emissions abatement devices (thermal oxidizers) where they are used. In general, Tier 3 methods for this source category yield far more accurate estimates than Tier 2 or Tier 1 methods. Even at the Tier 3 level, however, the emissions estimation methods used by the three facilities differed significantly in their levels of absolute uncertainty. The uncertainty of the one facility that does not thermally destroy its HFC–23 emissions dominates the uncertainty for the national emissions from this source category.
In general, the methods proposed in this rule are very similar to the procedures already being undertaken by the facilities to estimate HFC–23 emissions and to assure the quality of these estimates. The differences (and the rationale for them) are discussed in the HCFC–22 Production and HFC–23 Destruction TSD (EPA–HQ–OAR–2008–0508–015).
This section of the preamble includes two proposed monitoring methods for HCFC–22 production facilities and one for HFC–23 destruction facilities. The proposed monitoring methods differ for HCFC–22 facilities that do and do not use a thermal oxidizer connected to the HCFC–22 production equipment. All the monitoring methods rely on measurements of HFC–23 concentrations in process or emission streams and on measurements of the flow rates of those streams, although the proposed frequency of these measurements varies.
(1) Monitor the concentration of HFC–23 in the reaction product stream containing the HFC–23 (which could be either the HCFC–22 or the HCl product stream) on at least a daily basis. This proposed requirement is intended to account for day-to-day fluctuations in the rate at which HFC–23 is generated; this rate can vary depending on process conditions.
(2) Monitor the mass flow of the product stream containing the HFC–23 either directly or by weighing the other reaction product. The other product could be either HCFC–22 or HCl. Plants would be required to make or sum these measurements on at least a daily basis. If the HCFC–22 or HCl product were measured significantly downstream of the reactor (e.g., at storage tanks or the shipping dock), facilities would be required to add a factor that accounted for losses to the measurement. This factor would be 1.5 percent or another factor that could be demonstrated, to the satisfaction of the Administrator, to account for losses. This adjustment is intended to account for upstream product losses, which are estimated to range from one to two percent. Without the adjustment, HCFC–22 production and therefore HFC–23 generation at affected facilities would be systematically underestimated (negatively biased). A one-to two-percent underestimate could translate into an underestimate of HFC–23 emissions of 100,000 metric tons CO
We request comment on this proposed approach for compensating for the negative bias caused by HCFC–22 emissions. We specifically request comment on the 1.5 percent factor, which is the midpoint of the one-to-two-percent range of product loss rates cited by the affected facility. We also request comment on what methods and data would be required to verify a loss rate other than 1.5 percent, if a facility wished to demonstrate a lower loss rate. One option would be a mass-balance approach using measurements with very fine precisions (e.g., 0.2 percent or better).
(3) Facilities that do not use a thermal oxidizer connected to the HCFC–22
(4) Facilities would also be required to measure the masses of HFC–23 sold or sent to other facilities for destruction. This step would ensure that any losses of HFC–23 during filling of containers were included in the HFC–23 emission estimates for facilities that capture HFC–23 for use as a product or for transfer to a destruction facility.
(5) Facilities would also be required to estimate the HFC–23 emitted by subtracting the masses of HFC–23 sold or sent for destruction from the mass of HFC–23 generated.
This calculation assumes that all production that is not sold or sent to another facility for destruction is emitted. Such emissions may be the result of the packaging process; additional emissions can be attributed to the number of flanges in a line and other on-site equipment that is specific to each facility.
As discussed in the HCFC–22 Production and HFC–23 Destruction TSD (EPA–HQ–OAR–2008–0508–015), the initial testing and parametric monitoring that facilities currently perform on their oxidizers provides general assurance that the oxidizer is performing correctly. However, the proposed requirement to measure HFC–23 concentrations at the oxidizer outlet would provide additional assurance at relatively low cost. Even a one- or two-percent decline in the DE of the oxidizer could lead to emissions of over 100,000 metric tons CO
We are also proposing to require that HCFC–22 production facilities and HFC–23 destruction facilities measure concentrations using equipment and methods with an accuracy and precision of 5 percent or better at the concentrations of the samples.
(1) Calibrate gas chromatographs used to determine the concentration of HFC–23 by analyzing, on a monthly basis, certified standards with known HFC–23 concentrations that are in the same range (percent levels) as the process samples. This proposed requirement is intended to verify the accuracy and precision of gas chromatographs at the concentrations of interest; calibration at other concentrations does not verify this accuracy with the same level of assurance. The proposed requirement is similar to requirements in protocols for the use of gas chromatography, such as EPA Method 18,
(2) Initially verify each weigh scale, flow meter, and combination of volumetric and density measurements used to measure quantities that are to be reported under this rule, and calibrate it thereafter at least every year. We request comment on these proposed requirements.
We are proposing that in the cases when an upstream flow meter (i.e., near reactor outlet) is ordinarily used but is not available for some period, the facility can compensate by using downstream production measures (e.g., quantity shipped) and adding 1.5 percent to account for product losses. If HFC–23 concentration measurements are unavailable for some period, we propose that the facility use the average of the concentration measurements from just before and just after the period of missing data.
There is one proposed exception to these requirements: If either method would result in a significant under- or overestimate of the missing parameter (e.g., because the monitoring failure was linked to a process disturbance that is likely to have significantly increased the HFC–23 generation rate), then the facility would be required to develop an alternative estimate of the parameter and explain why and how it developed that estimate.
We request comment on these methods for estimating missing data. We also request comment on the option of estimating missing production data based on consumption of reactants, assuming complete stoichiometric conversion.
If you produce HCFC–22 and do not use a thermal oxidizer connected to the HCFC–22 production equipment, you would be required to report the total mass of the HFC–23 generated in metric tons, the mass of any HFC–23 packaged for sale in metric tons, the mass of any HFC–23 sent off site for destruction in metric tons, and the mass of HFC–23 emitted in metric tons. If you produce HCFC–22 and destroy HFC–23 using a thermal oxidizer connected to the HCFC–22 production equipment, you would be required to report the mass of HFC–23 emitted from the thermal oxidizer, the mass of HFC–23 emitted from process vents, and the mass of HFC–23 emitted from equipment leaks, in metric tons.
In addition, if you produce HCFC–22 you would also be required to submit the following supplemental data, as applicable, for QA purposes: Annual HCFC–22 production, annual consumption of reactants (including factors to account for quantities that typically remain unreacted), by reactant, annual mass of materials other than HCFC–22 and HFC–23 (i.e., unreacted reactants, HCl and other byproducts) that are permanently removed from the process, and the method for tracking startups, shutdowns, and malfunctions and HFC–23 generation/emissions during these events. You would also be required to report the names and addresses of facilities to which any HFC–23 was sent for destruction, and the quantities sent to each.
Where HCFC–22 production facilities have estimated missing data, you would be required to report the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data. Where the missing data was estimated by a method other than one of those specified, the owner or operator would be required to report why the specified method would lead to a significant under- or overestimate of the parameter(s) and the rationale for the methods used to estimate the missing data.
If you destroy HFC–23, you would be required to report the mass of HFC–23 fed into the thermal oxidizer, the mass of HFC–23 destroyed, and the mass of HFC–23 emitted from the thermal oxidizer. You would also be required to submit the results of your annual HFC–23 concentration measurements at the outlet of the oxidizer. In addition, you would be required to submit a one-time report similar to that required under EPA's stratospheric protection regulations at 40 CFR 82.13(j).
We propose that facilities report these data either because the data are necessary to verify facilities' calculations of HFC–23 generation, emissions, or destruction or because the data allow us to implement other QA checks (e.g., calculation of an HFC–23/HCFC–22 generation factor that can be compared across facilities and over time). We request comment on these proposed reporting requirements.
If you produce HCFC–22, you would be required to keep records of the data used to estimate emissions and records documenting the initial and periodic calibration of the gas chromatographs, scales, and flowmeters used to measure the quantities reported under this rule.
If you destroy HFC–23, you would be required to keep records of information documenting your one-time and annual reports.
These records are necessary to enable verification that the GHG emissions monitoring and calculations were performed correctly.
Approximately nine million metric tons of hydrogen are produced in the U.S. annually. Hydrogen is used for industrial applications such as petrochemical production, metallurgy, and food processing. Some of the largest users of hydrogen are ammonia production facilities, petroleum refineries, and methanol production facilities.
About 95 percent of all hydrogen produced in the U.S. today is made from natural gas via steam methane reforming. This process consists of two basic chemical reactions: (1) Reformation of the CH
Other processes used for hydrogen production include steam naptha reforming, coal or biomass gasification, partial oxidation of coal or hydrocarbons, autothermal reforming, electrolysis of water, recovery of byproduct hydrogen from electrolytic cells used to produce chlorine and other products, and dissociation of ammonia.
Hydrogen is produced in large quantities at approximately 77 merchant hydrogen production facilities (which produce hydrogen to sell) and 145 captive hydrogen production facilities (which consume hydrogen at the site where it is produced, e.g. petroleum refineries, ammonia, and methanol facilities). Hydrogen is also produced in small quantities at numerous other locations.
National emissions from hydrogen production were estimated to be approximately 60 million metric tons CO
The source category covered by the hydrogen production subpart of the proposed rule is merchant hydrogen production. CO
For additional background information on hydrogen production, please refer to the Hydrogen Production TSD (EPA–HQ–OAR–2008–0508–016).
In developing the threshold for hydrogen production, we considered emissions-based thresholds of 1,000
In selecting a threshold, we considered emissions data from merchant hydrogen facilities only, which together account for an estimated 15.2 million metric tons CO
Table P–1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds.
The hydrogen production industry is heterogeneous in terms of the types of facilities. There are some relatively large, emissions intensive facilities, but small facilities are common as well. At a 25,000 ton threshold, although 98.4 percent of emissions would be covered, only 53 percent of facilities would be required to report.
The proposed threshold for reporting emissions from hydrogen production is 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Hydrogen Production TSD (EPA–HQ–OAR–2008–0508–016). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Several domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from hydrogen production (e.g., the American Petroleum Institute Compendium, the DOE 1605(b), and the CARB Mandatory GHG Emissions Reporting Program). These methods coalesce around variants of two methods for merchant hydrogen production facilities: Direct measurement of CO
Based on our review of the above approaches, we propose both methods for quantifying GHG emissions from hydrogen production, to be implemented depending on current circumstances at your facility. If you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS does not measure process emissions, the proposed monitoring method is Option 2. You would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart C to estimate combustion-related emissions from each hydrogen production unit and any other stationary combustion units. This section of the preamble provides only those procedures for calculating and reporting process-related CO
The feedstock material balance method entails measurements of the quantity and carbon content of all feedstock delivered to the facility and of all products leaving the facility, with the assumption that all the carbon entering the facility in the feedstock that is not captured and sold outside the facility is converted to CO
We also considered three other methods for quantifying process-related emissions. The first method requires direct measurement of emissions by CEMS from all reporting facilities. The second method applies a constant proportionality factor, based on the facility's historical data on natural gas consumption, to the facility's hydrogen production rate. The third method we
The first method would generally increase accuracy of reported data. We invite comment on the practicality of adopting the first method. In general, the latter two methods are less certain, as they involve multiplying production and feedstock consumption data by default emission factors based on purity assumptions.
In contrast, the feedstock material balance method is more certain as it involves measuring the consumption and carbon content of the feedstock input. Because 95 percent of hydrogen is produced using steam methane reforming, and the carbon content of natural gas is always within 1 percent of the ratio: One mole of carbon per mole of natural gas, the local utility QA/QC requirements should be more than adequate.
Given the increase in accuracy of the direct measurement and feedstock material balance methods coupled with the minimal additional burden for facilities that already employ CEMS, we propose that facilities utilize the direct measurement method where currently employed, and the feedstock material balance method for all facilities that do not employ CEMS. We have concluded that this requirement does not add additional burden to current practices at the facilities, thereby minimizing costs. The primary additional burden for facilities associated with this method would be in conducting a gas composition analysis of the feedstock on a monthly basis, in cases where this information is not provided by the supplier.
The various approaches to monitoring GHG emissions are elaborated in the Hydrogen Production TSD (EPA–HQ–OAR–2008–0508–016).
Sources using CEMS to comply with this rule would be required to comply with the missing data requirements of proposed 40 CFR part 98, subpart C.
In the event that a facility lacks feedstock supply rates for a certain time period, we propose that facilities use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure. In the event that a monthly value for carbon content is determined to be invalid, an additional sample must be collected and tested. The likelihood for missing data is small, since the fuel meter and carbon content data are needed for financial accounting purposes.
We propose that facilities submit their annual CO
The data should include the total quantity of feedstock consumed for hydrogen production, the quantity of CO
A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and P.
We propose that each hydrogen production facility comply with the applicable recordkeeping requirements for stationary combustion units in proposed 40 CFR part 98, subpart C, which are also discussed in Section V.C of this preamble.
Also, we propose that each hydrogen production facility maintain records of feedstock consumption and the method used to determine the quantity of feedstock consumption, QA/QC records (including calibration records and any records required by the QAPP), monthly carbon content analyses, and the method used to determine the carbon content. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and P. These records consist of values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly.
The iron and steel industry in the U.S. is the third largest in the world, accounting for about 8 percent of the world's raw iron and steel production and supplying several industrial sectors, such as construction (building and bridge skeletons and supports), vehicle bodies, appliances, tools, and heavy equipment. In this proposed rule, we are defining the iron and steel production source category to be taconite iron ore processing facilities, integrated iron and steelmaking facilities, electric arc furnace steelmaking facilities that are not located at integrated iron and steel facilities, and cokemaking facilities that are not located at integrated iron and steel facilities. Coke, sinter, and electric arc furnace steel production operations at integrated iron and steel facilities are part of integrated iron and steel facilities. Direct reduced iron furnaces are located at and are part of electric arc furnace steelmaking facilities.
Currently, there are 18 integrated iron and steel steelmaking facilities that make iron from iron ore and coke in a blast furnace and refine the molten iron (and some ferrous scrap) in a basic oxygen furnace to make steel. In addition, there are over 90 electric arc furnace steelmaking facilities that produce steel primarily from recycled ferrous scrap. There are also eight taconite iron ore (pellet) processing facilities, 18 cokemaking facilities, seven of which are co-located at integrated iron and steel facilities, and one direct reduced iron furnace located at an electric arc furnace steelmaking facility.
The primary operation units that emit GHG emissions are blast furnace stoves (24 million metric tons CO
Based on production in 2007, GHG emissions from the source category are estimated at about 85 million metric tons CO
Although by-product recovery coke batteries and blast furnaces operations produce coke and pig iron, respectively, we are proposing that their emissions be reported as required for combustion units in proposed 40 CFR part 98, subpart C because the majority of their GHG emissions originate from fuel combustion. Emissions from the blast furnace operation occur primarily from the combustion of blast furnace gas and
• By-product recovery coke oven battery combustion stacks.
• Blast furnace stoves.
• Boilers.
• Process heaters.
• Reheat furnaces.
• Annealing furnaces.
• Flares.
• Ladle reheaters.
• Other miscellaneous combustion sources.
Emissions from the remaining operation units are generated from the carbon in process inputs and in some cases, from fuel combustion in the process. The process-related CO
• Taconite indurating furnaces.
• Nonrecovery coke oven battery combustion stacks.
• Coke pushing.
• Basic oxygen furnaces.
• Electric arc furnaces.
• Direct reduced iron furnaces.
• Sinter plants.
Emissions from nonrecovery coke batteries do not result from the combustion of a fuel input. In the nonrecovery battery, the volatiles that evolve as the coal is heated are ignited in the crown above the coal mass and in flues used to heat the oven. All of the combustible compounds distilled from the coal are burned, and the exhaust gases containing CO
Emissions of CH
Additional background information about GHG emissions from the iron and steel production source category is available in the Iron and Steel Production TSD (EPA–HQ–OAR–2008–0508–017).
In evaluating potential thresholds for iron and steel production, we considered emissions-based thresholds of 1,000 metric tons CO
Table Q–1 of this preamble illustrates that the various thresholds do not have a significant effect on the amount of emissions that would be covered. To avoid placing a reporting burden on the smaller specialty stainless steel producers which may operate as small businesses while still requiring the reporting of GHG emissions from those facilities releasing most of the GHG emissions in this source category, we are proposing a threshold of 25,000 metric tons CO
For a full discussion of the threshold analysis, refer to the Iron and Steel Production TSD (EPA–HQ–OAR–2008–0508–017). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating emissions from process and combustion sources (e.g. 2006 IPCC Guidelines, U.S. Inventory, the WBCSD/WRI GHG protocol, DOE 1605(b), TCR, EU Emissions Trading System, the American Iron and Steel Institute Protocol, International Iron and Steel Institute Protocol, and Environment Canada's mandatory reporting guidelines). We considered these methodologies for measuring or estimating GHG emissions from the iron and steel source category. The following five options were considered for reporting process-related CO
If you do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, we propose that Options 3, 4 or 5 could be implemented. You would be required to follow the requirements of proposed 40 CFR part 98, subpart C to estimate emissions of CO
We identified Options 3, 4, and 5 as the approaches that have acceptable uncertainty for facility-specific estimates. All of these options would provide insight into different levels of emissions caused by facility-specific differences in feedstock or process operation. Options 3, 4, and 5 are forms of the IPCC's highest tier methodology (Tier 3), therefore, we propose these options as equal options. After consideration of public comments, we may promulgate one or more of the options or a combination based on the additional information that is provided.
We considered but decided against Options 1 and 2 because the use of default values and lack of direct measurements results in a very high level of uncertainty in the emission estimates. These default approaches would not provide site-specific estimates of emissions that would reflect differences in feedstocks, operating conditions, fuel combustion efficiency, variability in fuels and other differences among facilities. In general, we decided against proposing existing methodologies that relied on default emission factors or default values for carbon content of materials because the differences among facilities described above could not be discerned, and such default approaches are inherently inaccurate for site-specific determinations. The use of default values is more appropriate for sector wide or national total estimates from aggregated activity data than for determining emissions from a specific facility. According to the IPCC's 2006 guidelines, the uncertainty associated with default emission factors for Options 1 and 2 is ±25 percent, and the uncertainty in the production data used with the default emission factor is ±10 percent, which results in a combined overall uncertainty greater than ±25 percent. If process-specific carbon contents and actual mass rate data for the process inputs and outputs are used (i.e., Option 3) or if direct measurements are used (i.e., Options 4 and 5), the guidelines state that the uncertainty associated with the emission estimates would be reduced.
For Option 3, we are proposing that facilities may estimate process emissions based on a carbon balance that uses facility-specific information on the carbon content of process inputs and outputs and measurements of the mass rate of process inputs and outputs. Monthly determinations of the mass of process inputs and outputs other than
While this proposed approach is consistent with how iron and steel production facilities are currently developing facility level GHG inventories, there are three components of this approach for which the Agency is requesting comment and supporting information. One issue is the ability to obtain accurate measurements of the process inputs and outputs, especially materials that are bulk solids and molten metal and slag. A second issue is the ability to obtain representative samples of the process inputs and outputs to determine the carbon content, especially for non-homogenous materials such as iron and steel scrap. The third issue is the level of uncertainty in the emission estimates for processes where there is a significant amount of carbon leaving the process with product (such as coke plants). These and other factors may result in an unacceptable level of uncertainty, especially for certain processes, when using the carbon balance approach to estimate emissions.
While we are proposing that emissions from blast furnace stoves and coke battery combustion stacks be reported as would be required for combustion sources under proposed 40 CFR part 98, subpart C, we are also requesting comment on how the carbon balance approach (Option 3) could be implemented as an alternative monitoring option for the entire blast furnace operation and the entire coke plant operation at integrated iron and steel facilities. Comments should address the advantages, disadvantages, types and frequency of measurements that should be required, and whether (and if so, how) the emissions can be determined with reasonable certainty. Comments must demonstrate that the procedures produce results that are reproducible and clearly specify the sampling methods and QA procedures that would ensure accurate results.
For the site-specific emission factor approach (Option 4), the owner or operator may conduct a performance test and determine CO
The site-specific emission factor for the process would be calculated in metric tons CO
We are also requesting comment on the advantages and disadvantages of Option 4, along with supporting documentation. We have concluded that there may be situations in which the site-specific emission factor approach may result in an uncertainty lower than that associated with the carbon balance approach and provide more reasonable emission estimates. An example is nonrecovery coke plants, where a carbon balance approach may result in an unacceptably high level of uncertainty from subtracting two very large numbers (carbon in with coal and carbon out with coke) to estimate emissions that could instead be accurately and directly measured at the combustion stack.
The primary sources of variability that affect CO
We are also proposing that you may use direct measurements, noting that CEMS (Option 5) provide the lowest uncertainty of the three options. This approach overcomes many of the limitations associated with other options considered such as accounting for the variability in emissions due to changes in the process, feed materials, or fuel over time. It would be applied to stacks that are already equipped with sampling ports and access platforms; consequently, it is technically feasible and cost effective. For those emission sources already equipped with CEMS, we are proposing that they be modified (if necessary) and used to determine CO
We are also proposing that CH
There are dozens of emission points and various types of fugitive emissions, not collected for emission through a stack, from the production processes and materials handling and transfer activities at integrated iron and steel facilities. These emissions from iron and steel plants have been of environmental interest primarily because of the particulate matter in the emissions. Examples include ladle metallurgy operations, desulfurization, hot metal transfer, sinter coolers, and the charging and tapping of furnaces. The information we have examined to date indicates that these emissions contribute very little to the overall GHG emissions from the iron and steel sector (probably on the order of one percent or less). For example, emissions of blast furnace gas may be emitted during infrequent process upsets (called “slips”) when gas is vented for a short period or from leaks in the ductwork that handles the gas. However, the mass of GHG emissions is expected to be small because most of the carbon in blast furnace gas is from carbon monoxide, which is not a GHG. Fugitive emissions and emissions from control device stacks may also occur from blast furnace tapping, the charging and tapping of basic oxygen furnaces and electric arc furnaces, ladle metallurgy, desulfurization, etc. However, we have no information that indicates CO
For process sources that use Option 3 (carbon balance) or Option 4 (site-specific emission factor), no missing data procedures would apply because 100 percent data availability would be required. For process sources that use Option 5 (direct measurement by CEMS), the missing data procedures would be the same as for units using Tier 4 in the general stationary fuel combustion source category in proposed 40 CFR part 98, subpart C.
We are proposing that facilities submit annual emission estimates for CO
In addition we propose that facilities submit the following data to assist in checks for reasonableness and for other data quality considerations: Total mass for all process inputs and outputs when the carbon balance is used for specific processes by calendar quarters, site-specific emission factor for all processes for which the site-specific emission factor approach is used, annual production quantity for taconite pellets, coke, sinter, iron, raw steel by calendar quarters, annual production capacity for taconite pellets, coke, sinter, iron, raw steel, annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast furnaces, direct reduced iron furnaces, and electric arc furnaces, and the quantity of CO
A full list of data that would be reported is included in proposed 40 CFR part 98, subparts A and Q.
In addition to the recordkeeping requirements for general stationary fuel combustion sources, we propose that the following additional records be kept to assist in QA/QC and verification purposes: GHG emission estimates from the iron and steel production process by calendar quarter, monthly total for all process inputs and outputs when the carbon balance is used for specific processes, documentation of calculation of site-specific emission factor for all processes for which the site-specific emission factor approach is used, monthly analyses of carbon content, and monthly production quantity for taconite pellets, coke, sinter, iron, and raw steel.
Lead is a metal used to produce various products such as batteries, ammunition, construction materials, electrical components and accessories, and vehicle parts. For this proposed rule, we are defining the lead production source category to consist of primary lead smelters and secondary lead smelters. A primary lead smelter produces lead metal from lead sulfide ore concentrates through the use of pyrometallurgical processes. A secondary lead smelter produces lead and lead alloys from lead-bearing scrap metal.
For the primary lead smelting process used in the U.S., lead sulfide ore concentrate is first fed to a sintering process to burn sulfur from the lead ore. The sinter is smelted with a
The predominate feed materials processed at U.S. secondary lead smelters are used automobile batteries, but these smelters can also process other lead-bearing scrap materials including wheel balance weights, pipe, solder, drosses, and lead sheathing. These incoming lead scrap materials are first pre-treated to partially remove metal and nonmetal contaminants. The resulting lead scrap is smelted (U.S. secondary lead smelters typically use either a blast furnace or reverberatory furnace). The molten lead from the smelting furnace is refined in kettle furnaces, and then cast into ingots or alloy products.
Lead production results in both combustion and process-related GHG emissions. Combustion-related CO
Currently there is one primary lead smelter operating in the U.S. There are 26 secondary lead smelters in the U.S. with widely varying annual lead production capacities ranging from approximately 1,000 metric tons to more than 100,000 metric tons. Total national GHG emissions from lead production in the U.S. were estimated to be approximately 0.9 million metric tons CO
Additional background information about GHG emissions from the lead production source category is available in the Lead Production TSD (EPA–HQ–OAR–2008–0508–018).
In developing the threshold for lead production facilities, we considered using annual GHG emissions-based threshold levels of 1,000 metric tons CO
Secondary lead smelters in the U.S. vary greatly in production capacity and include 10 small facilities with production capacities less than 4,000 tons per year. Table R–1 of this preamble shows approximately 92 percent of the GHG emissions that result from lead production are released from the one primary smelter and 12 secondary smelters that emit more than 25,000 metric tons CO
To avoid placing a reporting burden on the smaller secondary lead smelters which may operate as small businesses while still requiring the reporting of GHG emissions from those facilities releasing most of the GHG emissions in this source category, we are proposing a threshold of 25,000 metric tons CO
We reviewed existing domestic and international GHG monitoring guidelines and protocols including the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, U.S. GHG Inventory, the EU Emissions Trading System, the Canadian Mandatory Greenhouse Gas Reporting Program, and the Australian National Greenhouse Gas Reporting Program. These methods coalesce around the following four options for estimating process-related CO
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where CEMS would not adequately account for combustion and process related CO
We propose Option 2, due to the operating variations between the individual U.S. lead production facilities, including differences in equipment configurations, mix of lead feedstocks charged, and types of carbon materials used. Further, Option 2 would result in lower uncertainty as compared to applying a default emissions factor based approach to these units.
Although we are not proposing to require you to directly measure process emissions, unless you meet the requirements of proposed 40 CFR part 98, subpart C and the CEMS account for both combustion and process-relate emissions, you could opt to use direct measurement of CO
We decided not to propose the use of the default CO
We also decided not to propose Option 3 because of the potential for significant variations at lead smelters in the characteristics and quantities of the furnace inputs (e.g., lead scrap materials, carbonaceous reducing agents) and process operating parameters. A method using periodic, short-term stack testing would not be practical or appropriate for those lead smelters where the furnace inputs and operating parameters do not remain relatively consistent over the reporting period.
Further details about the selection of the monitoring methods for GHG emissions is available in the Lead Production TSD (EPA–HQ–OAR–2008–0508–018).
For smelting furnaces for which the owner or operator calculates process GHG emissions using site-specific carbonaceous input material data, the proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or “missing.” If the carbon content analysis of carbon inputs is missing or lost the substitute data value would be the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. In those cases when an owner or operator uses direct measurement by a CO
The proposed rule would require annual reporting of the total annual CO
Maintaining records of the information used to determine the reported GHG emissions is necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. In addition to the information reported as described in Section V.R.5 of this preamble, we propose that all facilities estimating emissions according to the carbon input method maintain records of each carbon-containing input material consumed or used (other than fuel) the monthly material quantity, monthly average carbon content determined for material, and records of the supplier provided information or analyses used for the determination. If you use the CEMS procedure, you would maintain the CEMS measurement records according to the procedures in proposed 40 CFR part 98, subpart C. These records would be required to be maintained onsite for 5 years. A complete list of records to be retained is included in the proposed rule.
Lime is an important manufactured product with many industrial, chemical, and environmental applications. Its major uses are in steel making, flue gas desulfurization systems at coal-fired electric power plants, construction, and water purification. Lime is used for the following purposes: Metallurgical uses (36 percent), environmental uses (29 percent), chemical and industrial uses (21 percent), construction uses (13 percent), and to make dolomite refractories (1 percent).
For U.S. operations, the term “lime” actually refers to a variety of chemical compounds. These compounds include calcium oxide (CaO), or high-calcium quicklime; calcium hydroxide (Ca(OH)
National emissions from the lime industry were estimated to be 25.4 million metric tons CO
For additional background information on lime manufacturing, please refer to the Lime Manufacturing TSD (EPA–HQ–OAR–2008–0508–019).
In developing the proposed reporting threshold for the lime manufacturing source category, we considered emissions-based thresholds of 1,000 metric tons CO
The lime manufacturing sector consists primarily of large facilities and a few smaller facilities. All facilities, except four, exceed the 25,000 metric tons CO
Consistent with National Lime Association recommendations, and in order to simplify the proposed rule and avoid the need to calculate and report whether the threshold value has been exceeded, we are proposing that all lime manufacturing facilities report GHG emissions. This captures 100 percent of emissions without significantly increasing the number of facilities that would have reported at 1,000, 10,000, or 25,000 metric ton thresholds. For a full discussion of the threshold analysis, please refer to the Lime Manufacturing TSD (EPA–HQ–OAR–2008–0508–019). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from lime manufacturing (
The third output method, developed by the National Lime Association, improves upon the IPCC Tier 2 procedure. In this method, facilities multiply the amount of lime produced at each kiln and the amount of calcined byproducts/wastes at the kiln by an emission factor. The emission factor is derived based on facility specific chemical analysis of the CaO and magnesium oxide (MgO) content of the lime produced at the kiln. To assess the composition of the lime and calcined byproduct/waste product, facilities would send samples to an off-site laboratory for analysis on a monthly basis following the procedures described in the National Lime Association's method protocol, along with the procedures in ASTM C25–06, “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime” (incorporated by reference, see proposed 40 CFR 98.7). This third output approach is also consistent with 1605(b)'s “A” rated approach and EU Emission Trading System's calculation B method.
We compared the various methods for estimating process-related CO
Under this proposed rule, if you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, you would use the National Lime Association method in this section of the preamble to calculate process-related CO
We are proposing the National Lime Association's output-based procedure because this method is already in use by U.S. facilities and the improvement in accuracy compared to default approaches can be achieved at minimal additional cost. The measurement of production quantities is common practice in the industry and is usually measured through the use of scales or weigh belts so additional costs to the industry are not anticipated. The primary additional burden for facilities would include conducting a CaO and MgO analysis of each lime product on a monthly basis (to be averaged on an annual basis). However, approximately two thirds of the lime manufacturing facilities in the U.S. are already undertaking sampling efforts to meet reporting goals set forth by the National Lime Association.
We request comment on the advantages and disadvantages of the IPCC Tier 3 method and supporting documentation. After consideration of public comments, we may promulgate the IPCC Tier 3 input-based procedure, the National Lime Association output-based procedure, or a combination based on additional information that is provided.
The various approaches to monitoring GHG emissions are elaborated in the Lime Manufacturing TSD (EPA–HQ–OAR–2008–0508–019).
It is assumed that a facility would be able to supply facility-specific production data. Since the likelihood for missing data is low because businesses closely track production, 100 percent data availability is required for lime production (by type) in the proposed rule. If analysis for the CaO and MgO content of the lime product are unavailable or “missing”, facility owners or operators would substitute a data value that is the average of the quality-assured values of the parameter immediately before and immediately after the missing data period.
We propose that in addition to stationary fuel combustion GHG emissions, you report annual CO
Maintaining records of the information used to determine the reported GHG emissions are necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. In addition to the data to be reported, we are proposing that the facilities maintain records of the calculation of emission factors, results of the monthly chemical composition analyses, total lime production for each kiln by month and type, total annual calcined byproducts/wastes produced by each kiln averaged from monthly data, and correction factor for byproducts/waste products for each kiln. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and S.
Magnesium is a high-strength and light-weight metal that is important for the manufacture of a wide range of products and materials, such as portable electronics, automobiles, and other machinery. The U.S. accounts for less than 10 percent of world primary
The magnesium metal production (primary and secondary) and casting industry typically uses SF
Cover gas systems are typically used to protect the surface of a crucible of molten magnesium that is the source for a casting operation and to protect the casting operation itself (e.g., ingot casting). SF
Total U.S. emissions of SF
We considered emissions thresholds of 1,000 metric tons CO
Under the proposed rule, magnesium metal production and parts casting facilities would have to report their total GHG emissions if those emissions exceeded 25,000 metric tons CO
The proposed emissions threshold of 25,000 metric tons CO
We also considered capacity-based thresholds of 26, 262, 656, and 2,622 metric tons, based on 100 percent capacity utilization and an SF
The emissions based threshold was selected over the capacity based threshold for several reasons. The emissions based threshold is simple to evaluate because magnesium production and processing facilities can use readily available data regarding consumption of SF
The emissions-based threshold of 25,000 metric tons CO
We reviewed a wide range of protocols and guidance in developing this proposal, including the 2006 IPCC Guidelines, EPA's SF
The methods described in these protocols and guidance were similar to the methods described by the IPCC Guidelines and the U.S. GHG Inventory methodology. These methods range from a Tier 1 approach, based on default consumption factors per unit Mg produced or processed, to a Tier 3 approach based on facility-specific measured emissions data.
Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, you would be required to follow the proposed monitoring method discussed below. The proposed method outlined below accounts for process-related SF
The proposed method for monitoring SF
We propose three options for measuring gas consumption:
1. Weighing gas cylinders as they are brought into and out of service allowing a facility to accurately track the actual mass of gas used.
2. Using a mass flow meter to continuously measure the mass of global warming gases used.
3. Performing a facility level mass balance for all global warming gases used at least once annually. Using this approach, a facility would review its gas purchase records and inventory to determine actual mass of gas used and subtract a 10 percent default heel factor to account for residual gas in cylinders returned to the gas suppliers.
When weighing cylinders to determine cover gas consumption, facilities would weigh all gas cylinders that are returned to the gas supplier, or have the gas supplier weigh the cylinders, to determine the residual gas still in the cylinder. The weight of residual gas would be subtracted from the weight of gas delivered to determine gas consumption. Gas suppliers can provide detailed monthly spreadsheets with exact residual gas amounts returned.
Facilities would be required to follow several procedures to ensure the quality of the consumption data. These procedures could be readily adopted, or would be based on information that is already collected for other reasons. Facilities would be required to track specific cylinders leaving and entering storage with check-out and weigh-in sheets and procedures. Scales used for weighing cylinders and mass flow meters would need to be accurate to within 1 percent of true mass, and would be periodically calibrated. Facilities would calculate the facility usage rate, compare it to known default emission rates and historical data for the facility, and investigate any anomalies in the facility usage rate. Finally, facilities would need to have procedures to ensure that all production lines have provided information to the manager compiling the emissions report, if this is not already handled through an electronic inventory system.
We are not proposing IPCC's Tier 1 or 3 methodologies for calculating emissions. Although the Tier 1 methodology is straightforward, the default consumption factor for the SF
In general, it is unlikely that cover gas consumption data would be missing. Facilities are expected to know the quantities of cover gas that they consume because facility operations rely on accurate monitoring and tracking of costs. Facilities would possess invoices from gas suppliers during a given year and many facilities currently track the weight of SF
However, where cover gas consumption information is missing, we
Facilities would be required to report total facility GHG emissions and emissions by process type: Primary production, secondary production, die casting, or other type of casting. For total facility and process emissions, emissions would be reported in metric tons of SF
Along with their total emissions from cover gas use, facilities would be required to submit supplemental data (as well as the supplemental data required in the combustion and calcination sections) including the type of production processes (e.g., primary, secondary, die casting), mass of magnesium produced or processed in metric tons for each process type, cover gas flow rate and composition, and mass of any CO
If data were missing, facilities would be required to report the length of time the data were missing, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated. Facilities would also submit an explanation for any significant change in emission rate. Examples could include installation of new melt protection technology that would account for reduced emissions in any given year, or occurrence or repair of leaks in the cover gas delivery system.
These non-emissions data need to be reported because they are needed to understand the nature of the facilities for which data are being reported and for verifying the reasonableness of the reported data.
We are proposing that magnesium producers and processors be required to keep records documenting adherence to the QA/QC requirements specified in the proposed rule. These records would include: Check-out and weigh-in sheets and procedures for cylinders; accuracy certifications and calibration records for scales; residual gas amounts in cylinders sent back to suppliers; and invoices for gas purchases and sales.
These records are being specified because they are the values that are used to calculate the GHG emissions that are reported. They are necessary to verify that the GHG emissions monitoring and calculations were done correctly and accurately.
Limestone (CaCO
For some of these applications, the carbonates undergo a calcination process in which the carbonate is sufficiently heated, generating CO
The use of limestone, dolomite and other carbonates is purely an industrial process source of emissions. Emissions from the use of carbonates in the manufacture of cement, ferroalloys, glass, iron and steel, lead, lime, pulp and paper, and zinc are elaborated in proposed 40 CFR part 98, subparts H, K, N, Q, R, S, AA and GG, since they are relatively significant emitters. Facilities that include only these source categories would not need to follow the methods presented in this section to estimate emissions from the miscellaneous use of carbonates. The methods presented in this section should be used by facilities that use carbonates in source categories other than those listed above, but which are covered by the proposed rule.
As estimated in the U.S. GHG Inventory, national process emissions from other limestone and dolomite uses (i.e., excluding cement, lime, and glass manufacturing) were 7.9 million metric tons CO
For additional background information on the use of limestone, dolomite and other carbonates, please refer to the Miscellaneous Uses of Carbonates TSD (EPA–HQ–OAR–2008–0508–021).
A separate threshold analysis is not proposed for uses of limestone, dolomite and other carbonates as these emissions occur in a large number of facilities across a range of industries. We propose that facilities with source categories identified in proposed 40 CFR 98.2(a)(1) or (a)(2) consuming limestone, dolomite and other carbonates calculate the relevant emissions from their facility, including emissions from calcination of carbonates, to determine whether they surpass the proposed threshold for that industry. Data were not available to quantify emissions from the calcination of carbonates across all industries; therefore, these emissions were considered where appropriate in the thresholds analysis for the respective industries.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from the use of limestone, dolomite and other carbonates (e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), the EU Emissions Trading System, and the Australian National Greenhouse Gas Reporting Program). These methodologies all rely on measuring the consumption of carbonate inputs, but differ in their use of default values. The range of default values reflect differing assumptions of the carbonate weight fraction in process inputs; for example, the 2006 IPCC Guidelines Tier 1 and 2 assume that carbonate inputs are 95 percent pure (i.e., 95 percent of the mass consumed is carbonate), whereas the Australian Program assumes a default purity of 90 percent for limestone, 95 percent for dolomite, and 100 percent for magnesium carbonate.
We propose that facilities estimate process emissions by measuring the type and quantity of carbonate input to a kiln or furnace and applying the appropriate emissions factors for the carbonates consumed. In order to assess the composition of the carbonate input, we propose that facilities send samples of each carbonate consumed to an off-site laboratory for a chemical analysis of
We also considered but decided not to propose simplified methods (similar to IPCC Tier 1 and 2) for quantifying process-related emissions from this source, which assumes that limestone and dolomite are the only carbonates consumed, and allow for the use of default fractions of the two carbonates (85 percent for limestone and 15 percent for dolomite). Default factors do not account for variability in relative carbonate consumption by other sources and therefore inaccurately estimate emissions.
The various approaches to monitoring GHG emissions are elaborated in the Miscellaneous Uses of Carbonates TSD (EPA–HQ–OAR–2008–0508–021).
We propose that 100 percent data availability is required. If chemical analysis on the fraction calcination of carbonates consumed were lost or missing, the analysis would have to be repeated. It is assumed that a facility would be able to supply facility-specific carbonate consumption data. The likelihood for missing data is low, as businesses closely track production inputs.
We propose that facilities report annual CO
We propose that facilities retain records on monthly carbonate consumption (by type), annual records on the fraction of calcination achieved (by carbonate type), and results of the annual chemical analysis. These records provide values that are directly used to calculate the emissions that are reported and are necessary to allow determination of whether the GHG emissions monitoring and calculations were done correctly. A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and U.
Nitric acid is an inorganic chemical that is used in the manufacture of nitrogen-based fertilizers, adipic acid, and explosives. Nitric acid is also used for metal etching and processing of ferrous metals. A nitric acid production facility uses oxidation, condensation, and absorption to produce a weak nitric acid (30 to 70 percent in strength). The production process begins with the stepwise catalytic oxidation of ammonia (NH
According to a facility-level inventory for 2006, there are 45 nitric acid production facilities operating in 25 States with a total of 65 process lines. These facilities represent the best available data at the time of this rulemaking. Using the facility-level inventory, production levels for 2006 have been estimated at 6.6 million metric tons of nitric acid and indicate an estimated 17.7 million metric tons CO
Stationary combustion emissions were not estimated at the source category level in the U.S. GHG Inventory. Stationary combustion emissions at nitric acid facilities may be associated with other chemical production processes as well (such as adipic acid production, phosphoric acid production, or ammonia manufacturing).
For additional background information on nitric acid production, please refer to the Nitric Acid Production TSD (EPA–HQ–OAR–2008–0508–022).
In developing the proposed threshold for nitric acid production, we considered emissions-based thresholds of 1,000 metric tons CO
We are proposing all nitric acid facilities report in order to simplify the rule and avoid the need for each facility to calculate and report whether it exceeds the threshold value. Facility-level emissions estimates based on plant production suggests that all known facilities, except two, exceed the 25,000 metric tons CO
This analysis, however, only took into account process-related emissions, as combustion-related emissions were not available. Had combustion-related emissions been included, it is probable that additional facilities would have been covered at each threshold. An “all in” threshold captures 100 percent of emissions without significantly increasing the number of facilities required to report. Finally, the cost of reporting using the proposed monitoring method does not vary significantly between the four different emissions based thresholds.
For a full discussion of the threshold analysis, please refer to the Nitric Acid Production TSD (EPA–HQ–OAR–2008–0508–022). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating these emissions (e.g. 2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), TCR, and EPA NSPS). These methodologies coalesce around the five options discussed below.
Options 4 and 5 are similar in that both use continuous monitoring to calculate N
Option 5 would provide the highest certainty of the three options and capture the smallest changes in N
We request comment, along with supporting documentation, on the advantages and disadvantages of using Options 3, 4 and 5. After consideration of public comments, EPA may promulgate one or more of these options or a combination based on the additional information that is provided.
We decided not to propose Options 1 and 2 because the use of default values and lack of direct measurements results in a high level of uncertainty. Although different default emissions factors have been developed for different processes (e.g., low pressure, high pressure) and abatement techniques, the use of these default values is more appropriate for sector wide or national total estimates than for determining emissions from a specific facility. Site-specific emission factors are more appropriate for reflecting differences in process design and operation.
The various approaches to monitoring GHG emissions are elaborated in the Nitric Acid Production TSD (EPA–HQ–OAR–2008–0508–022).
For process sources that use a site-specific emission factor, no missing data procedures would apply because the site-specific emission factor is derived from an annual performance test and used in each calculation. The emission factor would be multiplied by the production rate, which is readily available. If the test data is missing or lost, the test would have to be repeated. Therefore, 100 percent data availability would be required.
We propose that facilities report annual N
Capacity, actual production, and operating hours would be helpful in determining the potential for growth in the nitric acid industry. The production rate can be determined through sales records or by direct measurement using flow meters or weigh scales. This industry generally measures the production rate as part of normal operating procedures.
A list of abatement technologies would be helpful in assessing how widespread the use of abatement is in the nitric acid source category, cataloging any new technologies that are being used, and documenting the amount of time that the abatement technologies are being used.
A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and V.
We propose that facilities maintain records of significant changes to process, N
A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and V.
The U.S. petroleum and natural gas industry encompasses hundreds of thousands of wells, hundreds of processing facilities, and over a million miles of transmission and distribution pipelines. This section of the preamble identifies relevant facilities and outlines methods and procedures for calculating and reporting fugitive emissions (as defined in this section) of CH
The natural gas segment involves production, processing, transmission and storage, and distribution of natural gas. The U.S. also receives, stores, and processes imported liquefied natural gas (LNG) at LNG import terminals. The petroleum segment involves crude oil production, transportation and refining.
The relevant facilities covered in this section are offshore petroleum and natural gas production facilities, onshore natural gas processing facilities (including gathering/boosting stations), onshore natural gas transmission compression facilities, onshore natural gas storage facilities, LNG storage facilities, and LNG import facilities. Fugitive emissions from petroleum refineries are proposed for inclusion in the rulemaking, but these emissions are addressed in the petroleum refinery section (Section V.Y) of this preamble. Under this section of the preamble, we seek comment on methods for reporting fugitive emissions data from: On-shore petroleum and natural gas production and natural gas distribution facilities.
For this rulemaking, fugitive emissions from the petroleum and natural gas industry are defined as unintentional equipment emissions and intentional or designed releases of CH
Natural gas system fugitive CH
Petroleum segment fugitive CH
With over 160 different sources of fugitive CH
Another factor we considered in assessing the applicability of certain petroleum and natural gas industry fugitive emissions in a mandatory reporting program is the definition of a facility. In other words, what physically constitutes a facility? This definition is important to determine who the reporting entity would be, and to ensure that delineation is clear and double counting of fugitive emissions is minimized. For some segments of the industry, identifying the facility is clear since there are physical boundaries and ownership structures that lend themselves to identifying scope of reporting and responsible reporting entities (e.g., onshore natural gas processing facilities, natural gas transmission compression facilities, and offshore petroleum and natural gas facilities). In other segments of the industry, such as the pipelines between compressor stations, and more particularly onshore petroleum and natural gas production, such distinctions are not straightforward. In defining a facility, we reviewed current definitions used in the CAA and ISO definitions, consulted with industry, and reviewed current regulations relevant to the industry. The full results of our assessment can be found in the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023).
Following is a brief discussion of the proposed selected and excluded sources based on our analysis. Additional information can be found in the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023). This section of the preamble addresses only fugitive emissions. Combustion-related emissions are discussed in Section V.C of this preamble.
In 2006, offshore petroleum and natural gas production fugitive CO
Offshore petroleum and natural gas production facilities are proposed for inclusion due to the fact that this represents approximately 4 percent of emissions from the petroleum and natural gas industry, “facilities” are clearly defined, and major fugitive emissions sources can be characterized by direct measurement or engineering estimation.
Fugitive CH
Onshore natural gas processing facilities are proposed for inclusion due to the fact that these operations represent a significant emissions source, approximately 25 percent of emissions from the natural gas segment. “Facilities” are easily defined and major fugitive emissions sources can be characterized by direct measurement or engineering estimation.
Fugitive CH
Transmission compression facilities and underground natural gas storage facilities are proposed for inclusion due to the fact that these operations represent a significant emissions source, approximately 24 percent of emissions from the natural gas segment; “facilities” are easily defined, and major fugitive sources can be characterized by direct measurement or engineering estimation.
Fugitive CH
LNG storage facilities and LNG import facilities are proposed for inclusion due to the fact that fugitive emissions from these operations represent approximately 1 percent of emissions from natural gas systems. LNG storage “facilities” are defined as facilities that store liquefied natural gas in above ground storage tanks. LNG import terminal “facilities” are defined as facilities that receive imported LNG, store it in storage tanks, and release re-gasified natural gas for transportation.
We considered proposing the reporting of fugitive CH
Given the significance of fugitive emissions from the onshore petroleum and natural gas production, we would like to take comment on whether we should consider inclusion of this source category in the future. Specifically, we would like to take comment on viable ways to define a facility for onshore oil and gas production and to determine the responsible reporter. In addition, the Agency also requests comment on the merits and/or concerns with the corporate basin level reporting approach under consideration for onshore oil and gas production, as outlined below.
One approach we are considering for including onshore petroleum and natural gas production fugitive emissions in this reporting rule is to require corporations to report emissions from all onshore petroleum and natural gas production assets at the basin level. In such a case, all operators in a basin would have to report their fugitive emissions from their operations at the basin-level. For such a basin-level facility definition, we may propose reporting of only the major fugitive emissions sources; i.e., natural gas driven pneumatic valve and pump devices, well completion releases and flaring, well blowdowns, well workovers, crude oil and condensate storage tanks, dehydrator vent stacks, and reciprocating compressor rod packing. Under this scenario, we might suggest that all operators would be subject to reporting, perhaps exempting small businesses, as defined by the Small Business Administration.
This approach could substantially reduce the reporting complexity and require individual companies that produce crude oil and/or natural gas in each basin to be responsible for reporting emissions from all of their onshore petroleum and natural production operations in that basin, including from rented sources, such as compressors. In cases where hydrocarbons or emissions sources are jointly owned by more than one company, each company would report emissions equivalent to its portion of ownership.
We considered other options in defining a facility such as individual wellheads or aggregating all emissions sources prior to compression as a facility. However, such definitions result in complex reporting requirements and are difficult to implement.
We are seeking comments on reporting of the major fugitive emissions sources by corporations at the basin level for onshore petroleum and natural gas production.
The majority of fugitive emissions from the transportation of natural gas occur at the compressor stations, which are already proposed for inclusion in the rule and discussed above. We do not propose to include reporting of fugitive emissions from natural gas pipeline segments between compressor stations, or crude oil pipelines in the rulemaking due to the dispersed nature of the fugitive emissions, the difficulty in defining pipelines as a facility, and the fact that once fugitives are found, they are generally fixed quickly, not allowing time for monitoring and direct measurement of the fugitives.
Although fugitive emissions from a single vault, gate station or segment of pipeline in the natural gas distribution segment may not be significant, collectively these fugitive emissions sources contribute a significant share of fugitive emissions from natural gas systems.
We do not propose to include the natural gas distribution segment of the natural gas industry in this rulemaking due to the dispersed nature of the fugitive emissions and difficulty in defining a facility such that there would be an administratively manageable number of reporters.
One approach to address the concern with defining a facility for distribution would be to require corporate-level reporting of fugitive emissions from major sources by distribution companies. We seek comment on this and other ways of reporting fugitive emissions from the distribution sector.
We do not propose to include the crude oil transportation segment of the petroleum and natural gas industry in this rulemaking due to its small contribution to total petroleum and natural gas fugitive emissions, accounting for much less than 1 percent, and the difficulty in defining a facility.
We propose that facilities with emissions greater than 25,000 metric tons CO
To identify the most appropriate threshold level for reporting of fugitive emissions, we conducted analyses to determine fugitive emissions reporting coverage and facility reporting coverage at four different levels of threshold; 1,000 metric tons CO
A proposed threshold of 25,000 metric tons CO
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating fugitive emissions from oil and natural gas operations, including the 2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), and corporate industry protocols developed by the American Petroleum Institute, the Interstate Natural Gas Association of America, and the American Gas Association. The methodologies proposed vary by the emissions source, for example fugitive emissions versus vented emissions, versus emissions from flares (all of which are considered “fugitive” emissions in this rulemaking). Generally, approaches range from direct measurement (e.g., high volume samplers), to engineering equations (where applicable), to simple emission factor approaches based on national default factors.
Fugitive emissions from all affected emissions sources at the facility, whether in operating condition or on standby, would have to be monitored on an annual basis. The proposed monitoring method would depend on the fugitive emissions sources in the facility to be monitored. Each fugitive emissions source would be required to be monitored using one of the two monitoring methods: (1) Direct measurement or (2) engineering estimation. Table W–3 of this preamble provides the proposed fugitive emissions source and corresponding monitoring methods. General guidance on the monitoring methods is given below.
Fugitive emissions detection and measurement are both required in cases where direct measurement is being proposed. Infrared fugitive emissions detection instruments are capable of detecting fugitive CH
In the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023), we describe a particular method based on practicality of application. For example, using Toxic Vapor Analyzers or Organic Vapor Analyzers on very large facilities is not as cost effective as infrared fugitive emissions detection instruments. We propose that irrespective of the method used for fugitive natural gas emissions detection, the survey for detection must be comprehensive. This means that, on an annual basis, the entire population of emissions sources proposed for fugitive emissions reporting has to be surveyed at least once. When selecting the appropriate emissions detection instrument, it is important to note that certain instruments are best suited for particular applications and circumstances. For example, some optical infrared fugitive emissions detection instruments may not perform well in certain weather conditions or with certain colored backgrounds.
Infrared fugitive emissions detection instruments are able to scan hundreds of source components at once, allowing for efficient detection of emissions at large facilities; however, infrared fugitive emissions detection instruments are typically much more expensive than other options. Organic Vapor Analyzers and Toxic Vapor Analyzers are not able to detect fugitive emissions from many components as quickly; however, for small facilities this may provide a less costly alternative to infrared fugitive emissions detection without requiring overly burdensome labor to perform a comprehensive fugitive emissions survey. We propose that operators choose the instrument from the choices provided in the proposed rule that is best suited for their circumstance. Further information is contained in the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023).
For direct measurement, we have proposed that high volume samplers, meters (such as rotameters, turbine meters, hot wire anemometers, and others), and/or calibrated bags be designated for use. However, if fugitive emissions exceed the maximum range of the proposed monitoring instrument, you would be required to use a different instrument option that can measure larger magnitude emissions levels. For example, if a high volume sampler is pegged by a fugitive emissions source, then fugitive emissions would be required to be directly measured using either calibrated bagging or a meter. In the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023), we discuss multiple options for measurement where the range of emissions measurement instruments is seen as an issue. CH
Engineering estimation has been proposed for calculating CH
Before proposing the monitoring methods discussed above, we considered four additional measurement methods. The use of Method 21 or the use of activity and emission factors were considered for fugitive emissions detection and measurement. Although Toxic Vapor Analyzers and Organic Vapor Analyzers were considered but not proposed for fugitive emissions direct measurement they are acceptable for fugitive emissions detection.
Default fugitive CO
The proposed rule does not indicate a particular threshold for detection above which emissions measurement is required. This is because the different emissions detection instruments proposed have different levels and types of detection capabilities. Hence the magnitude of actual emissions can only be determined after measurement. This, however, does not serve the purpose of this rule in limiting burden on emissions reporting. A facility can have hundreds of small emissions (as low as 3 grams per hour) and it might not be practical to measure all such small emissions for reporting.
To address this issue we intend to incorporate one of the following two approaches in the final rule.
The first approach would provide performance standards for fugitive emissions detection instruments and usage such that all instruments follow a common minimum detection threshold. We may propose the use of the Alternate Work Practice to Detect Leaks from Equipment standards for infrared fugitive emissions detection instruments being developed by EPA. In such a case all detected emissions from components subject to this rule would require measurement and reporting.
The second approach would provide an emissions threshold above which the source would be identified as an “emitter” for emissions detection using Organic Vapor Analyzers or Toxic Vapor Analyzers. When using infrared fugitive emissions detection instruments all sources subject to this rule that have emissions detected would require emissions quantification. Alternatively, the operator would be given a choice of first detecting emissions sources using the infrared detection instrument and then verifying for measurement status using the emissions definition for Organic Vapor Analyzers or Toxic Vapor Analyzers.
We are seeking comments on using the two options discussed above for determining emission sources requiring measurement of emissions.
Some fugitive emissions by nature occur randomly within the facility. Therefore, there is no way of knowing when a particular source started emitting. This proposed rule requires annual fugitive emissions detection and measurement. The emissions detected and measured would be assumed to continue throughout the reporting year, unless no emissions detection is recorded at an earlier and/or later point in the reporting period. We recognize that this may not necessarily be true in all cases and that emissions reported would be higher than actual. Therefore, we are seeking comments on how this issue can be resolved without resulting in additional reporting burden to the facilities.
The petroleum and natural gas industry is already implementing voluntary fugitive emissions detection and repair programs. Such voluntary programs are useful, but pose an accounting challenge with respect to emissions reporting for this rule. The proposed rule requires annual detection and measurement of fugitive emissions. This approach does not preclude any facility from performing emissions detection and repair prior to the official detection, measurement, and reporting of emissions for this rule. We are seeking comments on how to avoid under-reporting of emissions as a result of a preliminary, “un-official” emissions
Fugitive emissions from a compressor are a function of the mode in which the compressor is operating. Typically, a compressor station consists of several compressors with one (or more) of them on standby based on system redundancy requirements and peak delivery capacity. Fugitive emissions at compressors in standby mode are significantly different than those from compressors that are operating. The rule proposes annual direct measurement of fugitive emissions. This may not adequately account for the different modes in which a particular compressor is operating through the reporting period. We are soliciting input on a method to measure emissions from each mode in which the compressor is operating, and the period of time operated in that mode, that would minimize reporting burden. Specifically, given the variability of these measured emissions, EPA requests comment on whether engineering estimates or other alternative methods that account for total emissions from compressors, including open ended lines, could address this issue of operating versus standby mode.
The fugitive emissions measurement instruments (i.e. high volume sampler, calibrated bags, and meters) proposed for this rule measure natural gas emissions. CH
The proposal requires data collection for a single source a minimum of once a year. If data are lost or an error occurs during fugitive emissions direct measurement, the operator should carry out the direct measurement a second time to obtain the relevant data point(s). Similarly, engineering estimates must account for relevant source counts and frequency of fugitive emissions releases throughout the year. There should not be any missing data for estimating fugitive emissions from petroleum and natural gas systems.
We propose that fugitive emissions from the petroleum and natural gas industry be reported on an annual basis. The reporting should be at a facility level with fugitive emissions being reported at the source type level. Fugitive emissions from each source type could be reported at an aggregated level. In other words, process unit-level reporting would not be required. For example, a facility with multiple reciprocating compressors could report fugitive emissions from all reciprocating compressors as an aggregate number. Since the proposed monitoring method is fugitive emissions detection and measurement at the source level, we determined that reporting at an aggregate source type level is feasible.
Fugitive emissions from all sources proposed for monitoring, whether in operating condition or on standby, would have to be reported. Any fugitive emissions resulting from standby sources would be separately identified from the aggregate fugitive emissions.
The reporting facility would be required to report the following information to us as a part of the annual fugitive emissions reporting: fugitive emissions monitored at an aggregate source level for each reporting facility, assuming no carbon capture and transfer offsite; the quantity of CO
Additional data are proposed to be reported to support verification: Engineering estimate of total component count; total number of compressors and average operating hours per year for compressors, if applicable; minimum, maximum and average throughput per year; specification of the type of any control device used, including flares; and detection and measurement instruments used. For offshore petroleum and natural gas production facilities, the number of connected wells, and whether they are producing oil, gas, or both is proposed to be reported. For compressors specifically, we proposed that the total number of compressors and average operating hours per year be reported.
A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and W.
The reporting facility shall retain relevant information associated with the monitoring and reporting of fugitive emissions to us, as follows; throughput of the facility when the fugitive emissions direct measurement was conducted, date(s) of measurement, detection and measurement instruments used, if any, results of the leak detection survey, and inputs and outputs to calculations or simulation software runs where the proposed monitoring method requires engineering estimation.
A full list of records to be retained is included inproposed 40 CFR part 98, subparts A and W.
The petrochemical industry consists of numerous processes that use fossil fuel or petroleum refinery products as feedstocks. For this proposed GHG reporting rule, the reporting of process-related emissions in the petrochemical industry is limited to the production of acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, and methanol. The petrochemicals source category includes production of all forms of carbon black (e.g., furnace black, thermal black, acetylene black, and lamp black) because these processes use petrochemical feedstocks; bone black is not considered to be a form of carbon black because it is not produced from petrochemical feedstocks. The rule focuses on these six processes because production of GHGs from these processes has been recognized by the IPCC to be significant compared to other petrochemical processes. Facilities producing other types of petrochemicals are not subject to proposed 40 CFR part 98, subpart X of this reporting rule but may be subject to 40 CFR part 98, subpart C, General Stationary Fuel Combustion Sources, or other subparts.
There are 88 facilities operating petrochemical processes in the U.S., and 9 of these operate either two or three types of petrochemical processes (e.g., ethylene and ethylene oxide). We estimate petrochemical production accounts for approximately 55 million metric tons CO
Total GHG emissions relevant to the petrochemical industry primarily include process-based emissions and emissions from combustion sources. Process-based emissions may be released to the atmosphere from process vents, equipment leaks, aerobic biological treatment systems, and in some cases, combustion source vents. CH
Emissions from the burning of process off-gas to supply energy to the process are also process-based emissions because the organic compounds being burned are derived from the feedstock chemical. These emissions are included with other process-based emissions if the mass balance monitoring method (described in Section V.X.3 of this preamble) is used to estimate process-based emissions, but they are included with combustion source emissions if CEMS are used to measure emissions from all stacks. Combustion source emissions include CO
CH
The ratio of process-based emissions to supplemental fuel combustion emissions varies among the various petrochemical processes. For example, process-based emissions dominate for acrylonitrile, ethylene, and ethylene oxide processes. Both process-based and supplemental fuel combustion emissions are important for carbon black and methanol processes. Emissions from supplemental fuel combustion predominate for ethylene dichloride processes. Equipment leak and wastewater emissions are both estimated to be less than 1 percent of the total emissions from petrochemical production.
For further discussion see the Petrochemical Production TSD (EPA-HQ-OAR–2008–0508–024).
We propose that every facility which includes within its boundaries methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon black production be subject to the requirements of this proposed rule.
In developing the proposed threshold for petrochemical facilities, we considered emissions-based thresholds of 1,000 metric tons CO
The emissions presented in Table X–1 of this preamble are the total emissions associated solely with the production of methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon black, not the total emissions from petrochemical facilities. An estimate of the total emissions was difficult to develop because many of these facilities contain multiple source categories. For example, some petrochemical operations occur at petroleum refineries. Other petrochemical manufacturing facilities produce chemicals such as ammonia or hydrogen that are also subject to reporting. In addition, numerous chemical manufacturing facilities produce other chemicals in addition to one or more of the petrochemicals; these facilities may have combustion sources associated with these other chemical manufacturing processes that are separate from the combustion sources for petrochemical processes.
Based on this analysis, 87 of the 88 petrochemical facilities have estimated combustion and process-based GHG emissions that exceed the 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Petrochemical Production TSD (EPA–HQ–OAR–2008–0508–024). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
We reviewed existing domestic and international GHG monitoring guidelines and protocols including the 2006 IPCC Guidelines and DOE 1605(b). Protocols included methods for both CO
This option would require continuous monitoring of liquid and gaseous flows using flow meters, measurement of solid feedstock and product flows using scales or other weighing devices, and determination of the carbon content of each feedstock and product/byproduct at least once per week. Supplemental fuel is not considered to be a feedstock because these fuels do not mix with process fluids (except in the furnace of a carbon black process) and would be calculated consistent with the monitoring methods in proposed 40 CFR part 98, subpart C.
In addition to using the carbon balance to estimate process-based CO
This option also would require the petrochemical facility owner to use engineering analyses to estimate flow and carbon content of gases discharged to flares using the same procedures described in Section V.Y.3 of this preamble for petroleum refineries. Just as at petroleum refineries, flares at petrochemical facilities are used to control a variety of emissions releases. In addition, the flow and composition of gas flared can change significantly. Therefore, the Agency is proposing the same methodology for petrochemical flares as for flares at petroleum refineries. Please refer to the petroleum refineries section (Section V.Y.3 of this preamble) for a discussion of the rationale for these procedures.
We request comment on this approach as well as on descriptions of differences in operating conditions for flares at petrochemical facilities and refineries that would warrant specification of different methodologies for estimating emissions.
In addition to measuring CO
If you do not operate and maintain an existing CEMS that measures total CO
Option 3 is expected to have the lowest measurement uncertainty. However, using CEMS to monitor all emissions at petrochemical facilities would be relatively costly. For emissions estimates produced using Option 2, the uncertainty in these estimates is expected to be relatively low for most petrochemical processes. For ethylene dichloride and ethylene processes, the uncertainty of the carbon balance approach may be higher since it is influenced by the measurements of inputs and outputs at the facility and the percentage of carbon in the final product. Uncertainty may be high where the percentage of carbon in the product is close to 100 percent (since subtracting one large number for process output from another large number for process input results in relatively large uncertainty in the difference, even if the uncertainty in the two large numbers is low). For the petrochemical processes, we have decided that Option 2 is reasonable for purposes of this proposed rulemaking. However, direct measurement may provide improved emissions estimates.
Option 1 was not proposed because the use of default values and lack of direct measurement results in a high level of uncertainty. These default approaches would not provide site-specific estimates of emissions that would reflect differences in feedstocks, operating conditions, catalyst selectivity, thermal/energy efficiencies, and other differences among plants. The use of default values is more appropriate for sector wide or national total estimates from aggregated activity data than for determining emissions from a specific facility.
We request comment on how to improve the emission estimates developed using the carbon balance approach (Option 2), including whether the uncertainty in the estimated emissions can be reduced (and if so, by how much), the advantages, disadvantages, types and frequency of other measurements that could be required, costs of alternatives, how the uncertainty of alternatives is estimated, and the QA procedures that should be followed to assure accurate measurement. For further discussion of our assumptions on the uncertainty of emissions estimates see the Petrochemical Production TSD (EPA–HQ–OAR–2008–0508–024).
Fugitive emissions from petrochemical production facilities have been of environmental interest primarily because of the VOC emissions. As noted above, we have concluded that fugitive CO
Second, Option 2 assumes all carbon entering the process is released as CO
Third, EPA is aware that a limited number of petrochemical facilities may produce petrochemicals as well as one or more other chemicals that are part of another source category (e.g.production of hydrogen for sale and the petrochemical methanol from synthesis gas created by steam reforming of CH
Fourth, we are proposing several methods for measuring the volume, carbon content and composition of feedstocks and products. There may be additional peer-reviewed and published measurement methodologies.
Public comment on each of these four issues is welcomed. Where applicable, supporting data and documentation on how emissions should be included, and if so, how these emissions can be estimated, including the advantages, disadvantages, types and frequency of measurements that could be required, costs of alternatives, how the uncertainty of alternatives is estimated, and the QA procedures that should be followed to assure accurate measurement.
The missing data procedures in proposed 40 CFR part 98, subpart C for combustion units are proposed for facilities that use CEMS to estimate emissions from both combustion sources and process vents. Similarly, if the mass balance option is used, the same procedures that apply to missing data for fuel measurements in proposed 40 CFR part 98, subpart C would also apply to missing flow and carbon content measurements of feedstocks and products. Specifically, the substitute data value for missing carbon content, CO
Where CEMS are used, the reporting requirements specified in proposed 40 CFR part 98, subpart C would apply. Where the carbon balance method is used, we propose that the following information be reported: Identification of the process, annual CO
The data to be reported under the proposed rule form the basis of the emissions calculations and are needed for us to understand the emissions data and verify reasonableness of the reported emissions. The Agency requests comment on the types of QA procedures that are most commonly conducted or recommended and the information that would be most useful in assessing uncertainty of the emissions estimates.
Petrochemical production facilities would be required to keep records of the information specified in proposed 40 CFR 98.3, as applicable. Under the carbon balance option, a facility also would be required to keep records of all feedstock and product flows and carbon content determinations. If a petrochemical production facility complies with the CEMS option, the additional records for CEMS listed in proposed 40 CFR 98.37 would also be required for all CEMS, including CEMS on process stacks that are not associated with combustion sources. These records document values that are directly used to calculate the emissions that are reported and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly.
Petroleum refineries are facilities engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen), or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives. There are 150 operating petroleum refineries in the U.S. and its territories. Emissions from petroleum refineries account for approximately 205 million metric tons CO
The combustion of catalyst coke in catalyst cracking units is also a significant contributor to the CO
Process emissions of CO
There are a variety of GHG emission sources at the refinery, which include: Asphalt blowing, delayed coking unit depressurization and coke cutting, coke calcining, blowdown systems, process vents, process equipment leaks, storage tanks, loading operations, land disposal, wastewater treatment, and waste disposal. To fully account for the refinery's GHG emissions, we propose that the emissions from these sources must also be reported.
Based on the emission sources at petroleum refineries, GHGs to report under proposed 40 CFR part 98, subpart Y are limited to CO
Four options were considered as reporting thresholds for petroleum refineries. Table Y–2 of this preamble illustrates the emissions and number of facilities that would be covered under the four options.
We are proposing that all petroleum refineries should report. This approach would ensure full reporting of emissions, affect an insignificant number of additional sources compared to the 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Petroleum Refineries TSD (EPA–HQ–OAR–2008–0508–025). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
We considered monitoring methods that are used or recommended for use from several sources including international groups, U.S. agencies, State agencies, and petroleum refinery trade organizations. For most emission sources, three general levels of monitoring options were evaluated: (1) Use of engineering calculations and/or default factors; (2) monitoring of process parameters (such as fuel consumption quantities and carbon content); and (3) direct emission measurement using CEMS for all emissions sources at a refinery.
Under this proposed rule, if you are required to use an existing CEMS to meet the requirements outlined in proposed 40 CFR part 98, subpart C, you would be required to use CEMS to estimate CO
For facilities that do not currently have CEMS that meet the requirements outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, the proposed monitoring method is Option 2. Option 2 accounts for process-related CO
You would be required to follow the calculation procedures, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of proposed 40 CFR part 98, subpart HH to estimate emissions from landfills, proposed 40 CFR part 98, subpart II to estimate emissions from wastewater and proposed 40 CFR part 98, subpart P to estimate emissions from hydrogen production (non-merchant hydrogen plants only).
Specifically, for fluid catalytic cracking units and fluid coking units that already have CEMS in place, we
The selected monitoring methods for this proposed rule generally follow those used in other reporting rules as well as those recommended in the American Petroleum Institute's
An engineering approach for estimating coke burn-off rates and calculating CO
The amount of coke burned in catalytic reforming units is estimated to be about 1 percent of the amount of coke burned in catalytic cracking units or fluid coking units; therefore, a simplified method is provided for estimating coke burn-off emissions for catalytic reforming units that do not monitor gas composition in the coke burn-off exhaust vent.
For further discussion of this source category and monitoring of its emissions, see the Petroleum Refineries TSD (EPA–HQ–OAR–2008–0508–025).
In those cases where you use direct measurement by a CO
The reporting requirements for combustion sources other than those associated with coke burn-off directly refer to those in proposed 40 CFR part 98, subpart C, General Stationary Fuel Combustion Sources. For other sources, we propose to report the identification of the source, throughput of the source (if applicable), the calculation methodology used, the total GHG emissions for the source, and the quantity of CO
The reporting requirements consist of actual GHG emission values as well as values that are directly used to calculate the emissions and are necessary in order to verify that the GHG emissions monitoring and calculations were done correctly. As there are high uncertainties associated with many of the ancillary emission sources at the refinery, separate reporting of the emissions for these separate sources is needed to fully understand the importance and variability of these ancillary emission sources. A complete list of information to report is contained in proposed 40 CFR 98.256.
The recordkeeping requirements in the general provisions of proposed 40 CFR part 98 apply for petroleum refineries. Specifically, refineries would be required to keep all records specified in proposed 40 CFR part 98, subpart A and summarized in Section III.E of this preamble. In addition, records of the data required to be monitored and reported under proposed 40 CFR part 98, subpart Y would be retained. If CEMS are used to quantify the GHG emissions, you would be required to keep additional records specified in proposed 40 CFR part 98, subparts A and Y. These records consist of values that are directly used to calculate the emissions and are necessary to enable verification that the GHG emissions monitoring and calculations were done correctly.
Phosphoric acid is a common industrial product used to manufacture phosphate fertilizers. Phosphoric acid is a product of the reaction between phosphate rock and, typically, sulfuric acid (H
Additionally, a second reaction occurs in which the limestone (CaCO
National emissions from phosphoric acid production facilities were estimated to be 3.8 million metric tons CO
The phosphoric acid production industry has many production sites that are integrated with mines; notably, three facilities import phosphate rock from Morocco.
For additional background information on phosphoric acid production, please refer to the Phosphoric Acid Production TSD (EPA–HQ–OAR–2008–0508–026).
In developing the threshold for phosphoric acid production, we considered emissions-based thresholds of 1,000 metric tons CO
There is no proposed threshold for reporting emissions from phosphoric acid production. Even at a 100,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Phosphoric Acid Production TSD (EPA–HQ–OAR–2008–0508–026). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
The methodology for estimating process-related emissions from phosphoric acid production is based on the U.S. GHG Inventory method discussed further in the Phosphoric Acid Production TSD (EPA–HQ–OAR–2008–0508–026). Most domestic and international GHG monitoring guidelines and protocols, such as the 2006 IPCC Guidelines do not provide estimation methodologies for process-related emissions from phosphoric acid production.
If you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, we propose that facilities estimate process-related CO
In order to assess the composition of the inorganic carbon input, we assume that vertically integrated phosphoric acid production facilities already have the necessary equipment on-site for conducting chemical analyses of the inorganic carbon weight fraction of the phosphate rock and that this analysis is conducted on a routine basis at facilities. Facilities importing rock from Morocco would send rock samples off-site for composition analysis. The inorganic carbon content would be determined on a per-batch basis. Multiplying the inorganic carbon content by the amount (mass) of phosphate rock processed and by the molecular weight ratio of CO
The various approaches to monitoring GHG emissions are elaborated in the Phosphoric Acid Production TSD (EPA–HQ–OAR–2008–0508–026).
The likelihood for missing data is low, as businesses closely track their purchase of production inputs. The Phosphoric Acid NSPS (40 CFR part 60, subpart T) requires continuous monitoring of phosphorus-bearing material (rock) to process. This requirement, along with the fact that the facility would closely monitor production inputs, results in low likelihood of missing data. Additionally, only 3 facilities within the U.S. are not vertically integrated with mines and may lack the necessary equipment to measure the inorganic carbon weight percent of the rock. Therefore, no missing data procedures would apply to CO
We propose that facilities report total annual CO
In addition to the data reported, we propose that facilities maintain records of inorganic carbon content chemical analyses on each batch of phosphate rock and monthly phosphate rock consumption (by the origin of the phosphate rock). These records provide values that are directly used to calculate the emissions that are reported and are necessary to allow determination of whether the GHG emissions monitoring and calculations were done correctly.
A full list of records that must be retained on-site is included in proposed 40 CFR part 98, subparts A and Z.
The pulp and paper source category consists of over 5,000 facilities engaged in the manufacture of pulp, paper, and/or paperboard products primarily from wood material. However, less than 10 percent of these facilities are expected to meet the applicability thresholds of this proposed rule. The approximately 425 facilities that the proposed rule is expected to cover mainly consist of facilities that include pulp, paper and paperboard facilities that operate fossil fuel-fired boilers in addition to operating other sources of GHG emissions (e.g., biomass boilers, lime kilns, onsite landfills, and onsite wastewater treatment systems).
Greenhouse gas emissions from the pulp and paper source category are predominantly CO
Table AA–1 of this preamble lists the GHG emission sources that may be
The method presented in this section of the preamble is to account for the use of make-up chemicals (e.g., sodium sulfate, calcium carbonate, sodium carbonate) that are added into the recovery loop (e.g., with the spent pulping liquor) at a pulp and paper facility to replace the small amounts of sodium and calcium that are lost from the recovery cycle at kraft and soda facilities. When carbonates are added, the carbon in these make-up chemicals, which can be derived from biomass or mineral sources, is emitted as CO
Affected facilities would be required to report total GHG emissions on a facility-wide basis for all source categories for which methods are presented in proposed 40 CFR part 98.
For the pulp and paper source category, the Agency proposes a GHG reporting threshold of 25,000 metric tons CO
As described in proposed 40 CFR part 98, subpart A, biomass-derived CO
In evaluating potential thresholds for the pulp and paper source category, we considered emissions-based thresholds of 1,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Pulp and Paper Manufacturing TSD (EPA–HQ–OAR–2008–0508–027). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Refer to proposed 40 CFR part 98, subparts C, HH, and II for monitoring methods for general stationary fuel combustion sources, landfills, and industrial wastewater treatment occurring on-site at pulp and paper facilities. This section of the preamble includes monitoring methods for calculating and reporting makeup chemicals at pulp and paper facilities. Additional details on the proposed monitoring options are elaborated in the Pulp and Paper Manufacturing TSD (EPA–HQ–OAR–2008–0508–027).
The proposed method for monitoring emissions from carbonate-based make-up chemicals used at chemical pulp facilities includes calculating the CO
For the monitoring methods detailed in proposed 40 CFR part 98, subpart C for general stationary combustion, it should be noted that biogenic CO
Where biomass is co-fired with fossil fuel, the appropriate methodology as required in proposed 40 CFR part 98, subpart C should be used. However, to minimize the burden on owners and operators of biomass-fired stationary combustion equipment, this proposed rule allows biogenic CO
Where available, like in the case of spent pulping liquor, we would require direct analysis of the HHV, rather than allowing the use of a default HHV. This is due to the variability in the HHV of spent pulping liquor across the industry and because a number of facilities already perform this analysis on a monthly basis. However, the proposed rule does not propose the use of default GHG emissions factors for spent pulping liquor at kraft pulp facilities. For sulfite and semichemical chemical recovery combustion units, we propose that sources conduct a monthly carbon content analysis of the spent pulping liquor for use in calculating the biomass CO
We are requesting comment on the appropriateness of today's proposed requirements for monthly measurement of spent pulping liquor HHV (kraft recovery furnaces) and monthly carbon content analysis of spent pulping liquor (sulfite and semichemical chemical recovery combustion units). We welcome data and documentation regarding the use of potential alternative methods or default emissions factors.
In addition, regarding the monitoring methods in proposed 40 CFR part 98, subpart C for general stationary combustion, the majority of biomass fuel consumed at pulp and paper mills is generated onsite, and thus, as required in proposed 40 CFR part 98, subpart C, the use of purchasing records might not be an option for these mills. As such, we are taking comment on appropriate details to be reported on volume or mass of biogenic fuel fed into stationary combustion units.
Lime kilns and calciners used in the pulp and paper source category are unique and are defined separately from lime kilns used in the commercial lime manufacturing industry because the source of the carbon in the calcium carbonate entering the kraft lime kiln is biogenic. The CO
Although CO
Refer to proposed 40 CFR part 98, subparts C, HH, and II for procedures for estimating missing data for stationary combustion, landfills, and industrial wastewater treatment occurring on-site at pulp and paper facilities.
Proposed 40 CFR part 98, subpart AA contains missing data procedures for process emissions. There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any monthly measurements are determined to be invalid. For missing spent pulping liquor flow rates, the lesser value of either the maximum fuel flow rate for the combustion unit, or the maximum flow rate that the fuel flowmeter can measure would be used. For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates).
Refer to proposed 40 CFR part 98, subparts C, HH, and II for reporting requirements for stationary combustion, landfills, and industrial wastewater treatment occurring on-site at pulp and paper facilities.
We propose that some additional data be reported to assist in verification of estimates, checks for reasonableness, and other data quality considerations, including: Annual emission estimates presented by calendar quarters (including biogenic CO
Refer to proposed 40 CFR part 98, subparts C, HH, and II for recordkeeping requirements for stationary combustion, landfills, and industrial wastewater treatment occurring on-site at pulp and paper facilities.
In addition to the recordkeeping requirements for general stationary fuel combustion sources in proposed 40 CFR part 98, subpart C, we propose that the following additional records be kept to assist in QA/QC, including: GHG emission estimates by calendar quarter by unit and facility, monthly consumption total of all biomass fuels and spent pulping liquor by unit and facility, monthly analyses of spent pulping liquor HHV or carbon content, monthly and annual steam production for each biomass unit, and monthly quantities of makeup chemicals (carbonates) used.
Silicon carbide (SiC) is primarily an industrial abrasive manufactured from silica sand or quartz and petroleum coke. Other uses of silicon carbide include semiconductors, body armor, and the manufacture of Moissanite, a diamond substitute. The silicon carbide source category is limited to the production of silicon carbide for abrasive purposes.
CO
Silicon carbide process emissions totaled 109,271 metric tons CO
For additional background information on silicon carbide production, please refer to the Silicon Carbide Production TSD (EPA–HQ–OAR–2008–0508–028).
In developing the reporting threshold for silicon carbide production, we considered emissions-based thresholds of 1,000 metric tons CO
There is no proposed threshold reporting level for GHG emissions from silicon carbide production facilities. The current estimate of emissions from the known facility just exceeds the highest threshold considered. Therefore, in order to simplify the rule and avoid the need for the facility to calculate and report whether the facility exceeds the threshold value, we propose that all facilities report in this source category. Requiring all facilities to report captures 100 percent of emissions, and small temporary changes to the facility would not affect reporting requirements.
For a full discussion of the threshold analysis, please refer to the Silicon Carbide Production TSD (EPA–HQ–OAR–2008–0508–028). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Monitoring of process emissions from silicon carbide production is addressed in both domestic and international GHG monitoring guidelines and protocols (the 2006 IPCC Guidelines and U.S. GHG Inventory). These methodologies can be summarized in two different options based on measuring either inputs or output of the production process. In general, the output or production-based method is less certain, as it involves multiplying production data by emission and correction factors that are likely default values based on carbon content (
Under this proposed rule, if you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C or where the CEMS would not adequately account for process emissions, we propose that facilities use an input based method to estimate process-related CO
We propose that facilities use an input-based method to estimate process-related CO
We assume that data on petroleum coke consumption is readily available to facilities. The measurement of production quantities is common practice in the industry and is usually measured through the use of scales or weigh belts so additional costs to the industry are not anticipated. The primary additional burden for facilities associated with this method is modifying their petroleum coke supplier contract to include an analysis of the carbon content of each delivery of petroleum coke. Alternatively, a facility can send the coke to an off-site laboratory for analysis of the carbon content by the applicable method incorporated by reference in proposed 40 CFR 98.7. We consider the additional burden of determining the carbon content of the coke raw material minimal compared to the increases in accuracy expected from the site specific emission factors.
We also considered a second method of estimating process-related CO
We propose that facilities estimate process-related CH
The various approaches to monitoring GHG emissions are elaborated in the Silicon Carbide Production TSD (EPA–HQ–OAR–2008–0508–028).
It is assumed that a facility would be readily able to supply data on annual petroleum coke consumption and its carbon contents. Therefore, 100 percent data availability is required.
We propose that facilities report the combined annual CO
In addition to the data reported, we propose that facilities maintain records of quarterly analyses of carbon content for consumed coke (averaged to an annual basis), annual consumption of petroleum coke, and calculations of emission factors. These records hold values directly used to calculate reported emissions and are necessary for future verification that GHG emissions monitoring and calculations were done correctly. A full list of records that must be maintained onsite is included in proposed 40 CFR part 98, subparts A and BB.
Soda ash (sodium carbonate, Na
Trona-based production methods are collectively referred to as “natural production” methods. “Natural production” emits CO
National emissions from natural soda ash manufacturing were estimated to be 3.1 million metric tons CO
Emissions from consumption of soda ash are not addressed in this proposed rule as they do not occur at the soda ash manufacturing source. Emissions from the use of soda ash would be reported by the glass manufacturing industry, which consumes the soda ash.
For additional background information on soda ash manufacturing, please refer to the Soda Ash Manufacturing TSD (EPA–HQ–OAR–2008–0508–029).
In developing the threshold for soda ash manufacturing, we considered emissions-based thresholds of 1,000 metric tons CO
Facility-level emissions estimates based on known plant capacities suggest that all known facilities exceed the highest (100,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Soda Ash Manufacturing TSD (EPA–HQ–OAR–2008–0508–029). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from soda ash manufacturing (e.g., the 2006 IPCC Guidelines, DOE 1605(b)). These methodologies coalesce around three different options:
Under this proposed rule, if you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, we propose that facilities estimate process-related CO
The proposed monitoring method requires facilities to use default stoichiometric emission factors (either 0.097 for trona consumed (ratio of ton of CO
We decided against applying a default emission factor and a default adjustment factor of 0.9 to either the total amount of trona consumed or soda ash produced. According to IPCC, the stoichiometric ratio used in the default emission factor equation is an exact number and assumes 100 percent purity of the input or output and the uncertainty of the default emission factor is negligible. However, simple application of default emission and adjustment factors would not take into account the actual fractional purities of either the trona input or soda ash output.
We also decided against proposing the second option to determine an annual site-specific emission factor. The stack from the calciner (kiln) emits CO
The third option we considered, but did not select as the proposed option, was continuous direct measurement of emissions from soda ash manufacturing. This option is consistent with the 2006 IPCC Guidelines Tier 3 method. Use of a CO
The various options of monitoring GHG emissions, as well as the domestic and international GHG monitoring guidelines and protocols researched, are elaborated in the Soda Ash Manufacturing TSD (EPA–HQ–OAR–2008–0508–029).
We propose that no missing data procedures would apply to estimating CO
We propose that reported data include annual CO
We propose that facilities keep information on monthly production of soda ash (metric tons), monthly consumption of trona (metric tons), and daily fractional purity (i.e., inorganic carbon content) of the trona or soda ash. A full list of records that must be retained onsite is included in the proposed rule.
The largest use of SF
Fugitive emissions of SF
PFCs are sometimes used as dielectrics and heat transfer fluids in power transformers. PFCs are also used for retrofitting CFC–113 cooled transformers. One PFC used in this application is perfluorohexane (C
According to the 2008 U.S. Inventory, total U.S. estimated emissions of SF
This source category comprises electric power transmission and distribution systems that operate gas-insulated substations, circuit breakers, and other switchgear, or power transformers containing sulfur-hexafluoride (SF
We propose to require electric power systems to report their SF
In addition, we considered emission-based threshold options of 1,000 metric tons CO
We selected a nameplate capacity threshold equivalent to the 25,000 metric tons CO
The proposed threshold is consistent with the threshold for other source categories. Based on information from the Partnership and from the Universal Database Interface Directory of Electric Power Producers and Distributors, we estimate that the nameplate capacity threshold covers only a small percentage of total utilities (10 percent or 141 utilities), while covering the majority of annual emissions (approximately 83 percent).
We decided not to propose the transmission-mile threshold because the relationship between emissions and transmission miles, while strong, is not as strong as that between emissions and nameplate capacity. On the one hand, some utilities have far larger nameplate capacities and emissions than would be expected based on their transmission miles. This is the case for some urban utilities that have large volumes of SF
Additional information supporting the selection of the threshold can be found in the SF
In developing the proposed approach, we reviewed the 2006 IPCC Guidelines, the SF
The proposed monitoring methods for calculating SF
We propose that you report all SF
The mass-balance approach works by tracking and systematically accounting for all facility uses of SF
The following equation describes the proposed utility-level mass-balance approach:
User Emissions = Decrease in SF
The same method is being proposed to estimate emissions of PFCs from power transformers.
IPCC Tier 2 methods use country-specific emission factors, but the Partner utilities have demonstrated by calculating their own utility-level emission rates that large variability exists in utility-level emission rates across the nation (i.e., emission rates range from less than one percent of a utility's SF
It is expected that utilities should have 100 percent of the data needed to perform the mass balance calculations for both SF
We propose annual reporting for facilities in the electric power systems industry. Each facility would report all SF
These data would be submitted because they are the minimum data that are needed to understand and reproduce the emission calculations that are the basis of the reported emissions. Transmission miles would be included in the reported data so that the reasonableness of the reported emissions could be quickly checked using default emission factors.
We propose that electric power systems be required to keep records documenting (1) their adherence to the QA/QC requirements specified in the proposed rule, and (2) the data that would be included in their emission reports, as specified above. The QA/QC requirements records include check-out sheets and weigh-in procedures for cylinders, residual gas amounts in cylinders sent back to suppliers, invoices for gas and equipment purchases or sales, and records of equipment nameplate capacity. The records that are being proposed are the minimum needed to reproduce and confirm emission calculations.
Titanium dioxide is a metal oxide commonly used as a white pigment in paint manufacturing, paper, plastics, rubber, ceramics, fabrics, floor covering, printing ink, and other applications. The majority of TiO
Titanium dioxide is produced through two processes: The chloride process and the sulfate process. According to USGS, most facilities in the U.S. employ the chloride process. Total U.S. production of titanium dioxide pigment through the chloride process was approximately 1.4 metric tons in 2006, a 7 percent increase compared to 2005. The chloride process emits process-related CO
The chloride process is based on two chemical reactions. Petroleum coke (C) is oxidized as the reducing agent in the first reaction in the presence of chlorine and crystallized iron titanium oxide (FeTiO
National emissions from titanium dioxide production were estimated to be 3.6 million metric tons CO
For additional background information on titanium dioxide production, please refer to the Titanium Dioxide Production TSD (EPA–HQ–OAR–2008–0508–031).
In developing the threshold for titanium dioxide production, we considered an emissions-based threshold of 1,000 metric tons CO
At the threshold levels of 1,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Titanium Dioxide Production TSD (EPA–HQ–OAR–2008–0508–031). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating process-related emissions from titanium dioxide production (e.g., the 2006 IPCC Guidelines, U.S. GHG Inventory, Australian Government's National Greenhouse and Energy Reporting System). These methods coalesce around two different options.
Under this proposed rule, if you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, we propose that facilities use the second option discussed above to estimate process-related CO
Under this approach the total amount of calcined petroleum coke consumed would be assumed to be directly converted into CO
We decided not to propose the option to use continuous direct measurement because it would not lead to significantly reduced uncertainty in the emissions estimate over the proposed option. Furthermore, the cost impact of requiring the installation of CEMS is high in comparison to the relatively low amount of emissions that would be quantified from the titanium production sector.
We decided not to propose the option to apply default emission factors to titanium dioxide production to quantify process-related emissions. Although default emissions factors have been developed for quantifying process-related emissions from titanium dioxide production, the use of these default values is more appropriate for sector wide or national total estimates than for determining emissions from a specific plant. Estimates based on site-specific consumption of reducing agents are more appropriate for reflecting differences in process design and operation. According to the 2006 IPCC Guidelines, the uncertainty associated with the proposed approach is much lower given that facilities closely track consumption of the calcined petroleum coke (accurate within 2 percent), whereas the uncertainty associated with the default emission factor is approximately 15 percent.
The various approaches to monitoring GHG emissions are elaborated in the Titanium Dioxide Production TSD (EPA–HQ–OAR–2008–0508–031).
It is assumed that a facility would be able to supply data on annual calcined petroleum coke consumption data. Therefore, 100 percent data availability is required for all parameters.
We propose that facilities submit process-related CO
In addition to the data reported, we propose that facilities maintain records of monthly production of titanium dioxide and monthly amounts of calcined petroleum coke consumed. These records hold values that are directly used to calculate the emissions
A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and EE.
Coal mining can produce significant amounts of CH
An active underground coal mine is a mine at which coal is produced by tunneling into the earth to a subsurface coal seam, which is then mined with equipment such as cutting machines, extracted and transported to the surface. In underground mines, CH
Mines that produce large amounts of CH
CH
At surface mines, CH
Post coal mining activities release emissions as coal continues to emit CH
At abandoned (closed) underground coal mines, CH
Total U.S. CH
We propose to require reporting of emissions from ventilation and degasification systems at active underground mines in this rule. This includes the fugitive CH
Although fugitive CO
For additional background information on coal mining, please refer to the Underground Coal Mines TSD (EPA–HQ–OAR–2008–0508–032).
In developing the threshold for active underground coal mines, we considered emissions-based thresholds of 1,000 metric tons CO
We propose that all active underground coal mines for which CH
For additional background information on the thresholds for coal mining, please refer to the Underground Coal Mines TSD (EPA–HQ–OAR–2008–0508–032). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating CH
Under this option, coal mine operators are required to either (a) independently collect quarterly samples of CH
MSHA inspectors currently perform quarterly mine safety inspections on mines emitting 100,000 cf CH
We would like to take comment on whether relying on MSHA sampling procedures,
For all ventilation systems with CH
We considered requiring mines to monitor ventilation CH
We also decided against requiring mines with CEMS installed at ventilation systems to use the continuous monitoring devices to monitor ventilation system CH
Finally, we decided not to propose Option 1, which applies default emission factors to coal production. We decided against the use of the default CH
We considered, but are not proposing, Option 1, which would estimate CH
We also considered, but are not proposing, Option 2, which would require mine operators to conduct periodic sampling of gob gas vent holes and any other degasification boreholes, rather than installing continuous monitoring. While such an approach would involve lower capital costs than CEMS, greater labor costs would be involved with traveling to each (often remote) well site to take samples. Moreover, this method would not accurately reflect fluctuations in gas quantity and CH
The various approaches to monitoring GHG emissions are elaborated in the Underground Coal Mines TSD (EPA–HQ–OAR–2008–0508–032).
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation) a substitute data value for the missing parameter shall be used in the calculations.
For each missing value of CH
We propose that coal mines report, for all ventilation shafts and degasification systems (e.g., all boreholes), the following parameters: CH
Reporters are to retain all data listed in Section V.FF.5 of this preamble. A full list of records to be retained onsite is included in proposed 40 CFR part 98, subparts A and FF.
Zinc is a metal used as corrosion-protection coatings on steel (galvanized metal), as die castings, as an alloying metal with copper to make brass, and as chemical compounds in rubber, ceramics, paints, and agriculture. For this proposed rule, we are defining the zinc production source category to consist of zinc smelters using pyrometallurgical processes and secondary zinc recycling facilities. Zinc smelters can process zinc sulfide ore concentrates (primary zinc smelters) or zinc-bearing recycled and scrap materials (secondary zinc smelters). A secondary zinc recycling facility recovers zinc from zinc-bearing recycled and scrap materials to produce crude zinc oxide for use as a feed material to zinc smelters. Many of these secondary zinc recycling facilities have been built specifically to process dust collected from electric arc furnace operations at steel mini-mills across the country.
There are no primary zinc smelters in the U.S. that use pyrometallurgical processes. The one operating U.S. pyrometallurgical zinc smelter processes crude zinc oxide and calcine produced from recycled zinc materials. These feed materials are first processed through a sintering machine. The sinter is mixed with metallurgical coke and fed directly into the top of an electrothermic furnace. Metallic zinc vapor is drawn from the furnaces into a vacuum condenser, which is then tapped to produce molten zinc metal. The molten metal is then transferred directly to a zinc refinery or cast into zinc slabs.
Secondary zinc recycling facilities operating in the U.S. use either of two thermal processes to recover zinc from recycled electric arc furnace dust and other scrap materials. For the Waelz kiln process, the feed material is charged to an inclined rotary kiln together with petroleum coke, metallurgical coke, or anthracite coal. The zinc oxides in the gases from the kiln are then collected in a baghouse or electrostatic precipitator. The second recovery process used for electric arc furnace dust uses a water-cooled, flash-smelting furnace to form vaporized zinc that is subsequently captured in a vacuum condenser. The crude zinc oxide produced at secondary zinc recycling facilities is shipped to a zinc smelter for further processing.
Zinc production results in both combustion and process-related GHG emissions. The major sources of GHG emissions from a zinc production facility are the process-related emissions from the operation of electrothermic furnaces at zinc smelters and Waelz kilns at secondary zinc recycling facilities. In an electrothermic furnace, reduction of zinc oxide using carbon provided by the charging of coke to the furnace produces CO
Total nationwide GHG emissions from zinc production facilities operating in the U.S. were estimated to be approximately 851,708 metric tons CO
Additional background information about GHG emissions from the zinc production source category is available in the Zinc Production TSD (EPA–HQ–OAR–2008–0508–033).
Zinc smelters and secondary zinc recycling facilities in the U.S. vary in types and sizes of the metallurgical processes used and mix of zinc-containing feedstocks processed to produce zinc products. In developing the threshold for zinc production facilities, we considered using annual GHG emissions-based threshold levels of 1,000, 10,000, 25,000 and 100,000 metric tons CO
We have concluded, based on emissions estimates using production capacity, that the one primary zinc facility exceeds all thresholds considered (Table GG–1 of this preamble). For the eight secondary zinc production facilities, just half are over a 25,000 metric tons CO
EPA reviewed existing domestic and international GHG monitoring guidelines and protocols including the 2006 IPCC Guidelines, U.S. GHG Inventory, the EU Emissions Trading System, the Canadian Mandatory GHG Reporting Program, and the Australian National GHG Reporting Program. These methods coalesce around the following four options for estimating process-related GHG emissions from zinc production facilities. Zinc smelters using hydrometallurgical processes (e.g., electrolysis) would not be subject to the estimating and reporting requirements in proposed 40 CFR part 98, subpart GG for zinc production because the processes used at these smelters do not release process-related GHG emissions. However, combustion GHG emissions from the process equipment at these smelters burning natural gas or other carbon-based fuels could be subject to the estimating and reporting requirements for general stationary fuel combustion units in proposed 40 CFR part 98, subpart C, depending on the level of total GHG emissions from the facility with respect to the reporting thresholds specified in proposed 40 CFR part 98, subpart A.
If you do not have CEMS that meet the conditions outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would not adequately account for process emissions, we propose that you follow Option 2, a carbon balance. You would still need to refer to proposed 40 CFR part 98, subpart C to estimate combustion-related CH
We decided not to propose the use of default CO
We also decided against proposing Option 3 because of the potential for significant variations at zinc production facilities in the characteristics and quantities of the furnace or Waelz kiln inputs (e.g., zinc scrap materials, carbonaceous reducing agents) and process operating parameters. A method using periodic, short-term stack testing would not be practical or appropriate for those zinc production facilities where the furnace or Waelz kiln inputs and operating parameters do not remain relatively consistent over the reporting period.
Further details about the selection of the monitoring methods for GHG emissions are available in the Zinc Production TSD (EPA–HQ–OAR–2008–0508–033).
For electrothermic furnaces or Waelz kilns for which the owner or operator calculates process GHG emissions using site-specific carbonaceous input material data, the proposed rule requires the use of substitute data whenever a quality-assured value of a parameter that is used to calculate GHG emissions is unavailable, or “missing.” If the carbon content analysis of carbon inputs is missing or lost the substitute data value would be the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. In those cases when an owner or operator uses direct measurement by a CO
The proposed rule would require annual reporting of the total annual CO
A complete list of data to be reported is included in proposed 40 CFR part 98, subparts A and GG.
Maintaining records of the information used to determine the reported GHG emissions is necessary to enable us to verify that the GHG emissions monitoring and calculations were done correctly. We propose that all affected facilities maintain records of monthly facility production quantities for each zinc product, number of facility operating hours each month, and the annual facility production quantity for each zinc product (in tons). If you use the carbon input procedure, you would record for each carbon-containing input material consumed or used (other than fuel) the monthly material quantity, monthly average carbon content determined for material, and records of the supplier provided information or analyses used for the determination. If you use the CEMS procedure, you would maintain the CEMS measurement records.
A complete list of records to be retained is included in proposed 40 CFR part 98, subparts A and GG.
After being placed in a landfill, waste is initially decomposed by aerobic bacteria, and then by anaerobic bacteria, which break down organic matter into substances such as cellulose, amino acids, and sugars. These substances are further broken down through fermentation into gases and short-chain organic compounds that form the substrates for the growth of methanogenic bacteria, which convert the fermentation products into stabilized organic materials and biogas.
CH
Waste decaying in landfills also produces CO
According to the 2008 U.S. Inventory, MSW landfills emitted 111.2 million metric tons CO
We propose to require reporting from open and closed,
The definition of landfills in this rule does not include land application units. Several refineries have land application units (also known as land treatment units) in which oily waste is tilled into the soil. We are seeking comment on the exclusion of land application units from this rule.
For additional background information on landfills, please refer to the Landfills TSD (EPA–HQ–OAR–2008–0508–034).
In developing the threshold for landfills, we considered thresholds of 1,000, 10,000, 25,000, and 100,000 metric tons CO
Table HH–1 of this preamble illustrates the emissions and facilities that would be covered under these various thresholds for MSW landfills. For landfills located at industrial facilities,
The proposed threshold for reporting emissions from MSW landfills is a generation threshold of 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Landfills TSD (EPA–HQ–OAR–2008–0508–034). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
This section of the preamble describes the proposed methods for estimating CH
Many domestic and international GHG monitoring guidelines and protocols include methodologies for estimating emissions from landfills (e.g., 2006 IPCC Guidelines, U.S. GHG Inventory, CCAR, EPA Climate Leaders, EU Emissions Trading System, TCR, EPA's Landfill Methane Outreach Program, DOE 1605(b), Australia's National Mandatory GHG Reporting Program (draft), NSPS/NESHAP, WRI/WBCSD GHG Protocol, and National Council of Air and Stream Improvement). In general, these methodologies include three methods for monitoring emissions: The modeling method, the engineering method, and the direct measurement method.
In order to estimate CH
We propose that the landfills use site-specific data to determine waste disposal quantities (by type of waste material disposed when material-specific waste quantity data are available) and use appropriate EPA and IPCC default values for all other factors used in the emissions calculation. To accurately estimate emissions using this method, waste disposal data are needed for the 50 year period prior to the year of the emissions estimate. Annual waste disposal data are estimated using receipts for disposal where available, and where unavailable, estimates based on national waste disposal rates and population served by the landfill.
We propose that landfills with gas collection systems continuously measure the CH
We are seeking comment on monthly sampling of landfill gas CH
To estimate CH
We are considering developing a tool to assist reporters in calculating generation and emissions from this source category. We have reviewed tools for calculating emissions and emissions reductions from these sources, including IPCC's Waste Model, and National Council of Air and Stream Improvement's GHG Calculation Tools for Pulp and Paper Mills, and EPA's LandGEM, and are seeking comment on the advantages and disadvantages of using these tools as a model for tool development and on the utility of providing such a tool.
Missing data procedures for landfills are proposed based on the monitoring methodology. In the case where a monitoring system is used, the substitute value would be calculated as the average of the values immediately proceeding and succeeding the missing data period. For prolonged periods of missing data when a monitoring system is used, or for other non-monitored data, the substitute data would be determined from the average value for the missing parameter from the previous year, or from equations specified in the rule (for waste disposal quantities). The proposed rule would require a complete record of all parameters determined from company records that are used in the GHG emissions calculations (e.g., disposal data, gas recovery data).
For purposes of the emissions calculation, we considered not deducting CH
We propose that landfills over the threshold report CH
Records to be retained include information on waste disposal quantities, waste composition if available, and biogas measurements. These records are needed to allow verification that the GHG emission monitoring and calculations were done correctly. A full list of records to be retained onsite is included in proposed 40 CFR part 98, subparts A and HH.
An industrial wastewater treatment system is a system located at an industrial facility which includes the collection of processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from waters
CH
Wastewater treatment also produces CO
In 2006, CH
The only wastewater treatment process emissions to be reported in this rule are those from onsite wastewater treatment located at industrial facilities, such as at pulp and paper, food processing, ethanol production, petrochemical, and petroleum refining facilities. POTWs are not included in this proposal because, as described in the Wastewater Treatment TSD (EPA–HQ–OAR–2008–0508–035), emissions from POTWs do not exceed the thresholds considered under this rule.
A separate threshold is not proposed for emissions from industrial wastewater treatment system as these emissions occur in a number of facilities across a range of industries (e.g., pulp and paper, food processing, ethanol production, petrochemical, and petroleum refining). As described in Sections III and IV of this preamble, a facility may have more than one source category and emissions from all source categories for which there are methods (e.g., emissions from industrial wastewater treatment systems) must be included in the facility's applicability determination. Please see the preamble sections for the relevant sectors for more information on the applicability determination for your facility.
Despite the fact that we are not proposing a separate threshold for industrial wastewater systems, there is analysis in the Wastewater Treatment TSD on the types of industrial facilities that would meet thresholds at the 1,000, 10,000, 25,000 and 100,000 million metric tons CO
For a full discussion of those threshold analyses, please refer to Wastewater Treatment TSD (EPA–HQ–OAR–2008–0508–035). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
For this proposal, we reviewed several protocols and programs for monitoring and/or estimating GHG emissions including the 2006 IPCC Guidelines, the U.S. GHG Inventory, CARB Mandatory GHG Emissions Reporting System, CCAR, National Council of Air and Stream Improvement, DOE 1605(b), EPA Climate Leaders, TCR, UNFCCC Clean Development Mechanism, the EU Emissions Trading System, and the New Mexico Mandatory GHG Reporting Program. These methodologies are all primarily based on the IPCC Guidelines.
Based on this review, we considered the following options.
We are also seeking comment on monthly sampling of digester gas CH
We are considering developing a tool to assist reporters in calculating emissions from this source category. EPA has reviewed tools for calculating emissions from these sources, such as National Council of Air and Stream Improvement's GHG Calculation Tools for Pulp and Paper Mills, and is seeking comment on the advantages and disadvantages of using these tools as a model for tool development, and the utility of providing such a tool.
For additional information on the proposed method, please see the 2006 IPCC Guidelines,
On the occasion that a facility lacks data needed to determine the emissions from wastewater treatment over a period of time, we propose that the facility apply an average facility-level value for the missing parameter from measurements of the parameter preceding and following the missing data incident, as specified in the proposed rule. The proposed rule would require a complete record of all parameters determined from company records that are used in the GHG emissions calculations (e.g., production data, biogas combustion data).
For purposes of the emissions calculations, we considered not deducting CH
EPA proposes that industrial wastewater treatment plants over the threshold report annually both CH
A full list of data to be reported is included in proposed 40 CFR part 98, subparts A and II.
Records to be retained include information on influent flow rate, COD concentration, wastewater treatment system types, and digester biogas measurements. These records are needed to allow verification that the GHG emission monitoring and calculations were done correctly. A full list of records to be retained onsite is included in proposed 40 CFR part 98, subparts A and II.
A manure management system is a system that stabilizes or stores livestock manure, or does both. Anaerobic manure management systems include liquid/slurry handling in uncovered anaerobic lagoons, ponds, tanks, pits, or digesters. At some digesters, material other than manure is treated along with the manure. Manure management systems in which treatment is primarily aerobic include daily spread, solid storage, drylot, and manure composting. For the purposes of this rule, a manure management facility consists of uncovered anaerobic lagoons, liquid/slurry systems, pits, digesters, and drylots (including systems that combine drylot with solid storage) onsite manure composting, other poultry manure systems, and cattle and swine deep bedding systems. The manure management system does not include other onsite units and processes at a livestock operation unrelated to the stabilization and/or storage of manure.
When livestock manure are stored or treated, the anaerobic decomposition of materials in the manure management system produces CH
Manure management also produces CO
According to the 2008 U.S. Inventory, CH
Manure management systems which include one or more of the following components are to report emissions under this rule: Manure handling in uncovered anaerobic lagoons, liquid/slurry systems, pits, digesters, and drylots, including systems that combine drylot with solid storage. Emissions to be reported include those from the systems listed above, and also emissions from any high rise houses for caged laying hens, broiler and turkey production on litter, deep bedding systems for cattle and swine, and manure composting occuring onsite as part of the manure management system.
This source category does not include systems which consist of only components classified as daily spread, solid storage, pasture/range/paddock, or manure composting. For detailed descriptions of system types, please
A facility that is subject to the proposed rule only because of emissions from manure management would also report CO
In developing the threshold for manure management, we considered thresholds of 1,000, 10,000, 25,000, and 100,000 metric tons CO
To estimate the number of farms at each threshold, EPA first developed a number of model farms to represent the manure management systems that are most common on large farms and have the greatest potential to exceed the GHG thresholds. Next, we used EPA's GHG inventory methodology for manure management, to estimate the numbers of livestock that would need to be present to exceed the threshold for each model farm type. Finally, we combined the numbers of livestock required on each model farm to meet the thresholds with U.S. Department of Agriculture (USDA) data on farm sizes to determine how many farms in the United States have the livestock populations required to meet the GHG thresholds for each model farm.
Table JJ–1 of this preamble presents the estimated head of livestock that would meet the thresholds evaluated for the highest GHG-emitting common manure management systems for beef (steers and heifers at a feedlot), dairy (cows at an uncovered anaerobic lagoon, heifers on dry lot without solids separation), swine (farrow to finish at an uncovered anaerobic lagoon), and poultry (layers and pullets at an uncovered anaerobic lagoon).
Other types of farms and manure management systems could require significantly higher head counts to meet the thresholds considered: Meeting the 25,000 tCO
Although data are available at the national level on the number of farms of certain sizes, most of the population sizes needed to meet these thresholds occur in the largest farm size categories, in which data are not sufficiently disaggregated to determine how many farms of such sizes exist. For example, the largest dairy farm size category for which data is available is “1,000 head or more.” The number of dairy farms with populations large enough to meet thresholds for 10,000 metric tons CO
The proposed threshold for reporting emissions from manure management systems is the emission threshold of 25,000 metric tons CO
We are seeking comment on the option of using a generation threshold instead of the proposed emissions threshold. In the generation threshold option, the CH
Many domestic and international GHG programs provide monitoring guidelines and protocols for estimating emissions from manure management (e.g., the 2006 IPCC Guidelines, the U.S. GHG Inventory, DOE 1605(b), CARB Mandatory GHG Emissions Reporting System, CCAR, EPA Climate Leaders, TCR, UNFCCC Clean Development Mechanism, EPA AgSTAR, and Chicago Climate Exchange). These methodologies are all based on the IPCC Guidelines.
Based on the review of these methods, we considered the following options.
We propose that the amount of volatile solids excreted be calculated using (1) calculation of manure quantity entering the system using livestock population data and default values for average animal mass and manure generation, and (2) monthly sampling and testing of excreted manure for total volatile solids content.
We are seeking comment on the option of using facility-specific livestock population and mass, and default values for volatile solids rate to estimate total volatile solids, instead of measured values. We are also seeking comment on whether a different sampling and testing frequency, such as quarterly, would be more appropriate than monthly.
The maximum amount of CH
We are also seeking comment on monthly sampling of digester gas CH
CH
We propose that the amount of nitrogen entering the manure management system be measured through (1) calculation of manure quantity entering the system using livestock population data and default values for average animal mass and manure generation, and (2) monthly sampling and testing of excreted manure for total nitrogen content.
We are seeking comment on the option of using facility-specific livestock population and mass, and default values for nitrogen excretion rate to estimate total N, instead of measured values.
Each manure management system type has an associated default N
Estimate and report GHG emissions by adding the CH
Direct measurement is another option we considered but are not proposing in this rule. A direct measurement system must be complete both spatially (in that all emissions pathways are covered) and temporally (as emissions can vary greatly due to changes in population, diet, and conditions at the facility) and would hence be difficult and expensive to implement accurately.
We are considering developing a tool to assist reporters in calculating emissions from this source category. There are several existing tools for calculating emissions and emissions reductions from manure management systems, including EPA's FarmWare and CCAR's Livestock Project Reporting Protocol. We are seeking comment on
The various approaches to monitoring GHG emissions, as well as specific cost information, are elaborated in the Manure Management TSD (EPA–HQ–OAR–2008–0508–036).
On the occasion that a facility lacks sufficient data to determine the emissions from manure management over a period of time, we propose that the facility apply an average facility-level value for the missing parameter from measurements of the parameter preceding and following the missing data incident, as specified in the proposed rule. The proposed rule would require a complete record of all parameters determined from company records that are used in the GHG emissions calculations (e.g., historical livestock population data, biogas destruction data).
For emissions calculation purposes, EPA considered not deducting CH
EPA proposes that facilities report CH
Records to be retained include information on animal population, manure management system types, animal waste characteristics, and digester biogas measurements. These records are needed to allow verification that the GHG emission monitoring and calculations were done correctly. A full list of records to be retained onsite is included in proposed 40 CFR part 98, subparts A and JJ.
Proposed 40 CFR part 98, subpart KK would require reporting by facilities or companies that introduce or supply coal into the economy (e.g., coal mines, coal importers, and waste coal reclaimers). These facilities or companies (in the case of coal importers and exporters) would report on the CO
Facilities that use coal for energy purposes should refer to proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). Facilities that use coal for non-energy uses (e.g., as a reducing agent in metal production such as ferroalloys, zinc, etc.) should refer to the relevant subparts of the proposed rule. Underground coal mine operators who are included in this subpart should also refer to proposed 40 CFR part 98, subpart FF (Underground Coal Mines) in order to account for any combustion and fugitive emissions separately, as described in Sections III and IV of this preamble. A description of the requirements related to the conversion of coal to liquid fuel is covered in Section V.LL of this preamble.
Coal is a combustible black or brownish-black sedimentary rock composed mostly of carbon and hydrocarbons. It is the most abundant fossil fuel produced in the U.S. Over 90 percent of the coal used in the U.S. is used to generate electricity. Coal is also used as a basic energy source in many industries, including cement and paper. In 2006, the combustion of coal for useful heat and work resulted in emissions of 2,065.3 million metric tons CO
The supply chain for delivering coal to consumers is relatively straightforward. It includes coal mines or importers, in some cases coal washing or preparation onsite or at dedicated offsite plants, and transport (usually by rail) to consumers. The U.S. typically produces nearly all of its domestic coal needs; in 2007, domestic coal production accounted for 97 percent of domestic coal consumption. A relatively small share of coal consumed in the U.S. (3 percent in 2007) is imported from other countries, and a small share of U.S. production is exported for use abroad (5 percent in 2007).
In determining the most appropriate point in the supply chain of coal for reporting potential CO
We are proposing to include all active coal mines, coal importers, coal exporters, and reclaimers of waste coal as reporters under this subpart.
We are proposing to require all owners or operators of active underground and surface coal mines to report under proposed 40 CFR part 98, subpart KK. There were 1,365 active coal mines (both underground and surface mines) operating in the U.S. in 2007, according to the MSHA. Currently, coal mines routinely monitor coal quantity and coal quality data for use in coal sale contracts as well as for reporting requirements to various State and Federal agencies.
We are proposing that importers of coal into the U.S. report under proposed 40 CFR part 98, subpart KK. Reporting for coal importers is proposed at the company level, as opposed to the facility level, because the importers of record are typically companies, and these companies currently track and report imports. Most of the 36 million tons of coal that were imported to the U.S. in 2007 were used for power generation. A small number of electric utility companies were responsible for the large majority of coal imports in 2006.
We are proposing that exporters of coal report under proposed 40 CFR part 98, subpart KK. In 2007, 59.2 million tons of coal produced (mined) in the U.S. were exported. Coal exporters may include coal mining companies who directly sell their coal to entities outside the U.S., or other retailers who export the coal (typically via barge from one of several U.S. ports). Coal exports are included in proposed 40 CFR part 98, subpart KK so that the total supply of coal (and associated GHG emissions) into the U.S. economy is balanced against the coal that leaves the country. Typically, coal exporters characterize the quantity (tons) and heat value of the coal. Thus, this reporting requirement would impose a minimal additional burden on coal exporters.
We are proposing that reclaimers of waste coal report under proposed 40 CFR part 98, subpart KK. In some parts of the U.S., waste coal that was mined decades ago and placed in waste piles is now being actively recovered and sold to end users. Because this coal is technically not being “mined” but is nonetheless entering the U.S. economy for the first time, facilities that reclaim or recover such waste coal from waste coal piles and sell or deliver it to end-users are being included for reporting under proposed 40 CFR part 98, subpart KK as waste coal reclaimers. Because these facilities would need to collect data on the quantity and quality (e.g., heat value) of their product, this reporting requirement should impose a minimal additional burden on coal reclaimers.
We considered but are not proposing that facilities that convert coking coal into industrial coke and importers of coke report under proposed 40 CFR part 98, subpart KK. U.S. coke imports in 2007 constituted only 2.5 million tons (about 0.2 percent of total U.S. coal production) and can therefore be considered negligible. Most domestically consumed coal-based coke (87 percent) is derived from domestically-mined coal or imported coal, and therefore the inclusion of coal mines and coal importers in this subpart already provide for coverage of carbon contained in the coke (and the potential CO
We considered but are not proposing that coal preparation plants located offsite from coal mines report the potential CO
Instead of requiring coal mines to report as coal suppliers, we also considered, but are not proposing, that rail operators report the quantity of coal they transport. We have determined that requiring reporting on coal transport would add complexity without increasing the accuracy of information on potential CO
We request comment on the inclusion of active underground and surface coal mines, coal importers, coal exporters, and waste coal reclaimers, and the exclusion of offsite preparation plants, coke importers and coke manufacturing facilities, and coal rail transporters from reporting requirements under proposed 40 CFR part 98, subpart KK. For additional background information on suppliers of coal, please refer to the Suppliers of Coal TSD (EPA–HQ–OAR–2008–0508–037).
In considering a threshold for coal suppliers, we considered the application of the following emissions-based thresholds for each affected company or facility under proposed 40 CFR part 98, subpart KK (e.g., coal mine, coal importer, coal exporter, or waste coal reclaimer): 1,000 metric tons CO
For this rule, we propose to include all active underground and surface coal mines, with no threshold. Of the approximately 1,365 active coal mines operating in 2007, the 25,000 metric tons CO
For a full discussion of the threshold analysis, please refer to the Suppliers of Coal TSD (EPA–HQ–OAR–2008–0508–037). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
We are proposing the reporting of the amount of coal produced or supplied to the economy annually, as well as the CO
The only GHG required to be reported under this subpart is CO
We are proposing that coal mines, coal importers, coal exporters, and reclaimers of waste coal use a mass-balance method to calculate CO
We propose that coal suppliers be required to report both the total weight of coal produced or supplied annually (tons per year), as well as either the carbon content (carbon mass fraction) or coal HHV, which can be a proxy for carbon content. In practice, coal suppliers routinely and frequently monitor both the weight and energy content of coal for contractual purposes (e.g., daily measurements of tonnage and analyses of the BTU, sulfur, and ash content of coal) as well as for reporting requirements to various State and Federal agencies. We propose that all coal suppliers report these routinely-collected data, and use them as a basis for estimating the CO
For the purpose of this calculation, we propose that larger coal mines (i.e., coal mines that produce over 100,000 short tons of coal per year) use mine-specific, carbon content values.
Generally, the carbon content of coal can be determined through one of two procedures. The most accurate method is to determine the coal's carbon content (carbon mass fraction) directly through ultimate analysis of the coal's chemical constituents. An alternative method is to measure the coal's energy content (HHV, which is often expressed in units of MMBTU per unit weight) and use it as an indicator of the coal's carbon content. This is done by establishing a statistically significant correlation between the coal's heating value and the carbon content of the coal, and using this correlation to estimate the carbon content (carbon mass fraction) of a given batch of coal with known heating value. For instance, a linear relationship between coal heating value and coal carbon content can be established. This alternative approach is convenient because heat value measurements of coal are taken routinely and frequently by coal mines, coal importers, coal exporters, and coal retailers.
For the purpose of proposed 40 CFR part 98, subpart KK, EPA proposes that coal mines that produce over 100,000 short tons of coal per year have two options for reporting the carbon content of their coal: (1) Daily measurements of coal carbon content through ultimate analyses (daily sampling and analyses, reported as annual weighted average), or (2) a combination of daily measurements of coal HHV through proximate analyses and monthly measurements of carbon content through ultimate analyses, using an established, statistically significant correlation to estimate the daily weighted average coal carbon content (mass fraction), as described in the rule. We propose that a minimum of one year of data be used to establish such a mine-specific statistically significant correlation between the coal carbon
EPA proposes that coal mines with annual coal production less 100,000 short tons use either one of the above approaches for estimating carbon content, or use a third alternative. This alternative involves estimating the coal's carbon content based only on daily measurements of coal HHV through proximate analyses and a default CO
EPA proposes that all coal importers, coal exporters, and reclaimers of waste coal use any of three above approaches for estimating carbon content based on measurements per shipment in place of daily measurements if preferred. We seek comment on this measurement approach.
We propose that the ASTM Method D5373 should be used as the standard for all ultimate analyses.
We considered, but are not recommending, an option to allow all coal mines to use default coal carbon content values instead of site-specific values or measurements. Existing information available on the variability of carbon content for coal from USGS, the U.S. GHG Inventory, EIA's GHG Inventory, and the IPCC indicate that default values introduce considerable uncertainty into the emissions calculation. Given the large share of total GHG emissions represented by use of coal in the U.S. economy, we view the direct measurement or estimation of site-specific carbon content values as necessary. We seek comment on an appropriate approach for reporters—such as importers—who estimate a weighted annual average GCV according to specified methodology that is not listed with a corresponding default coal carbon content value in table KK–1 of this rule. Further information on various approaches to monitoring GHG emissions is elaborated in the Suppliers of Coal TSD (EPA–HQ–OAR–2008–0508–037).
We have determined that some of the information to be reported by coal mines, coal importers, coal exporters, and waste coal reclaimers is routinely collected as part of standard operating practices (e.g., coal tonnage). For these cases, we expect no missing data would occur.
Typically, coal is weighed using automated systems on the conveyor belt or at the loadout facility. In general, the weighing and sampling of coal at coal mines are conducted at about the same time to ensure consistency between quantity and quality of coal. In this rule, EPA proposes that the most current version of NIST Handbook 44 published by Weights and Measures Division, National Institute of Standards and Technology be used as the standard practice for coal weighing. In cases where coal supply data are not available, reporters may estimate the missing quantity of coal supplied, using documentation for the quantity of coal received by end-users or other recipients. For any periods during which mine scales are not operational or records are unavailable, estimates of coal production at the mine may be estimated using an average of values of production immediately preceding and following the missing data period, or other standard industry practices, such as estimating the volume of coal transported by rail cars and coal density to estimate total coal weight in tons. For additional background information on coal weighing, please refer to the Suppliers of Coal TSD (EPA–HQ–OAR–2008–0508–037).
In cases where carbon content or HHV measurements are missing, reporters may estimate the missing value based on an weighted average value for the previous seven days.
We propose that coal mines, coal importers, coal exporters, and waste coal reclaimers each report to us annually on the CO
Information from coal mines should be reported at the facility level, and should include mine name, mine MSHA identification number, name of operating company, coal production coal rank or classification (e.g., anthracite, bituminous, sub-bituminous, or lignite), facility-specific measured values of coal carbon content or HHV that are used to calculate CO
Coal importers, coal exporters, and waste coal reclaimers should report company name and technical contact information (name, e-mail, phone).
Coal importers should report at the corporate level. Coal importers already measure coal quantity for each shipment entering the U.S. Importers generally conduct proximate analyses on each shipment to assure that coal quality meets the coal specification under contract. Some importers may also conduct ultimate analysis. Coal importers should report the quantity of coal imported, coal rank or classification (e.g., anthracite, bituminous, sub-bituminous, or lignite), country of origin, origin-specific measured values of coal carbon content and HHV that are used to calculate CO
Coal exporters should report, at the corporate level, the quantity of coal exported, coal rank or classification (e.g.anthracite, bituminous, sub-bituminous, or lignite), name and MSHA identification number of mine of origin, country of destination, mine-specific measured values of coal carbon content or HHV that are used to calculate CO
Waste coal reclaimers should report, at the facility level, the quantity of coal recovered or reclaimed (tons/yr), coal rank or classification (e.g., anthracite, bituminous, sub-bituminous, or lignite), name of mine of origin, state of origin, mine-specific measured values of coal carbon content or HHV that are used to calculate CO
A full list of data to be reported is contained in the rule. These data to be reported form the basis of calculating potential CO
We considered, but are not proposing an option in which we would obtain facility-specific data for coal production through access to existing Federal
A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and KK. EPA proposes that the following records specific to suppliers of coal be kept onsite: Daily production of coal, annual weighted average of coal carbon content values (if measured), annual weighted average of coal HHV, calibration records of any instruments used onsite (e.g., if coal analyses are done onsite), and calibration records of scales or other equipment used to weigh coal.
These records consist of data that are directly used to calculate the potential CO
We are proposing to include facilities that produce coal-based liquids as well as importers and exporters of coal-based liquids in this source category. Owners and operators of coal-to-liquids facilities, or “producers”, importers, and exporters would report on the CO
The carbon in coal-based liquids would already be captured in the reporting from domestic coal suppliers and importers, but we believe that it is important for climate policy development to have additional information on a unique and potentially growing source of liquid fuels. As discussed in Sections III and IV of this preamble, emissions resulting from the combustion and other uses of coal-based liquids, as well as emissions generated in the production of coal-based liquids, are addressed in other sections of the preamble, particularly Section V.C of this preamble (General Stationary Fuel Combustion Sources), Section V.D (Electricity Generation), and Section V.FF (Underground Coal Mines).
The output fuels from coal-to-liquids processes are compositionally similar to standard petroleum-based products e.g., gasoline, diesel fuel, jet fuel, light gases etc. The most common processes for converting coal to liquids are direct and indirect liquefaction. In the direct process, coal is processed directly to liquid. In the indirect process, coal is first gasified, and then liquefied.
Once manufactured, the supply chain for coal-based liquids to consumers is basically the same as it is for refined petroleum products. Liquid fuels are moved from the manufacturing facility to a terminal, at which point they may be blended or mixed with other products, before entering the downstream distribution chain. Imported coal-based liquids would enter the U.S. in the same way that refined and semi-refined petroleum products enter the country. In determining the most appropriate point in the supply chain of coal-based liquids, we followed the decision-making process applied to suppliers of petroleum products discussed in Section V.MM of this preamble, and selected coal-to-liquids facilities (analogous to refineries), and importers and exporters. For further information, see the Coal to Liquids TSD (EPA–HQ–OAR–2008–0508–038). We request comment on the approach of establishing a separate source category and subpart for suppliers of coal-based liquids, and the selection of coal-to-liquids facilities and corporate importers and exporters of coal-based liquids. We also request comment on whether or not importers of liquid-based fuels are likely to have the necessary information with which to distinguish coal-based liquids from conventional petroleum-based liquids.
In developing the threshold for suppliers of coal-based liquids, EPA considered the emissions-based threshold of 1,000 metric tons CO
We also propose that all importers and exporters of coal-based liquids report under this rule. While the number of existing importers and exporters is very small in comparison to importers and exporters of petroleum products, importers of coal-based liquids would be required to track fuel quantities as part of routine business operations, and report to DOE and other Federal agencies.
For further information, see the Coal to Liquids TSD (EPA–HQ–OAR–2008–0508–038). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
We are proposing that producers, importers, and exporters of coal-based liquids calculate potential CO
We have determined that the information to be reported by suppliers of coal-based liquids is routinely collected by facilities and entities as part of standard operating practices, and therefore 100 percent data availability would be required. Typically, coal-based liquids would be metered directly at multiple stages. In cases where metered data are not available, reporters may estimate the missing volumes based on contracted maximum daily quantities and known conditions of receipt and delivery during the period when data are missing.
We propose that producers, importers, and exporters report CO
We considered but did not propose an option in which we would obtain facility-specific data for coal-based liquids through access to existing Federal government reporting databases, such as those maintained by EIA. EPA believes that comparability and consistency in reporting processes across all facilities included in the entire rule are vital, particularly with respect to timing of submission, reporting formats, QA/QC, database management, missing data procedures, transparency and access to information, and recordkeeping.
A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and LL.
We are proposing that refineries as well as importers and exporters of petroleum products be included in this source category. Owners or operators of petroleum refineries, or “refiners,” and importers that introduce petroleum products into the U.S. economy would be required to report on the CO
End users of petroleum products are addressed in other sections of this preamble, such as Section V.C (General Stationary Fuel Combustion Sources), and direct, onsite emissions at petroleum refineries are covered in Section V.Y of this preamble.
The total estimated GHG emissions resulting from the combustion of petroleum products in the U.S. in 2006 was 2,417 million metric tons CO
Petroleum products are ultimately consumed in one of two ways: Either through combustion for energy use, or through a non-energy use such as petrochemical feedstocks or lubricants. Combustion of petroleum products produces CO
The following list, while not comprehensive, illustrates the types of products that EPA considers to fall under the category of petroleum products:
• Motor vehicle and nonroad gasoline and diesel fuels.
• Jet fuel and kerosene.
• Aviation gasoline.
• Propane and other LPGs.
• Home heating oil.
• Residual fuel oil.
• Petrochemical feedstocks.
• Asphalt.
• Petroleum coke.
• Lubricants and waxes.
As discussed earlier in this preamble, one of our objectives when determining which entities would fall within a source category was to identify logical data reporting points or groups of facilities that were relatively small in number but that could provide a comprehensive set of data for the particular source category. Of all the parties that make up the petroleum products supply chain, we have concluded that petroleum refiners
There are approximately 150 operating petroleum refineries in the U.S. and its territories. Our thresholds analysis in Section V.MM.2 of this preamble, however, only reflects data on the 140 refineries that reported atmospheric distillation capacity to EIA (at DOE) in 2006. Petroleum products from these refineries account for approximately 90 percent of U.S. consumption. Given the coverage provided by a relatively small number of facilities, we propose that all refiners be subject to the reporting requirements for petroleum product suppliers and that they report to EPA on a facility-by-facility basis. For refiners that trade semi-refined and refined petroleum products between facilities, leading to a
To account for refined and semi-refined petroleum products that are not produced at U.S. refineries, we are proposing to include importers under this source category. Importers currently report to EPA on petroleum products designated for transportation or non-road mobile end-uses. This rule would include all importers regardless of end-use designations. The number of importing companies varies from year to year, but it is typically on the order of 100 to 200.
We are also proposing to include under this source category exporters of refined and semi-refined petroleum products in order to have information on petroleum products that are produced but not consumed in the U.S. The rationale to include reporting from exporters is to be able to account for petroleum products that are consumed in other countries and that do not contribute to direct CO
Many refiners are also importers and exporters of petroleum products. EPA is proposing that such refiners separately report data on the petroleum products that they produce on a facility-by-facility basis and report at a corporate level the petroleum products they import or export. The rationale for this separate reporting is that we are generally proposing coverage at the facility level where feasible (e.g., refineries) and proposing corporate reporting only where facility-level coverage may not be feasible (e.g., importers and exporters). In addition, the separation simplifies reporting in cases where a company that owns or operates multiple refineries may have a consolidated arrangement for imports of refined and semi-refined products destined for its refineries and for other consumers, or for exports.
We considered but are not proposing to include parties that are involved in upstream petroleum production. We believe the number of domestic oil drillers and well owners is prohibitively large and represents only a portion of the amount of crude petroleum that is processed into finished products to be used in the U.S.
We are not proposing to include retail gas station owners and oxygenate blenders to report to EPA as suppliers of petroleum products. Retail gas station owners and oxygenate blenders mostly handle transportation fuel and fuel used in small engines. Because we are interested in GHG emissions from all petroleum products combusted or consumed in the U.S. and can obtain information on such products on a more aggregated basis directly from refiners and importers, we are proposing to exclude retail gas station owners and oxygenate blenders from reporting under this rule.
We are not proposing to include operators of terminals or pipelines, blenders of blendstocks, or transmix processors in this source category because we believe that refiners and importers can provide comprehensive information on petroleum products supplied in the U.S. with a lower risk of double-counting petroleum products. A given quantity of refined or semi-refined petroleum product may pass between multiple terminals and blending facilities, so asking terminal or pipeline operators, blenders of blendstock, or transmix processors to report information on incoming and outgoing products would likely result in unreliable data for estimating GHG emissions from petroleum products.
Liquid fossil fuel products can be derived from feedstocks other than petroleum crude, such as coal and natural gas. Suppliers of coal-based products are covered under Section V.LL of this preamble, Suppliers of Coal-Based Liquid Fuels. Primary suppliers of natural gas-based products are covered in Section V.NN of this preamble, Suppliers of Natural Gas and Natural Gas Liquids. We are proposing to require all reporters in this source category to report data on the NGLs they supply to or export from the economy because these products may not currently be captured under Section V.NN of this preamble, Suppliers of Natural Gas and NGLs. The natural-gas related reporting requirements are discussed in Section V.MM.5 of this preamble.
This section of the preamble is focused on suppliers of petroleum products, so EPA is not proposing to include primary
Certain petroleum products can be co-processed or blended with renewable fuels. We are proposing a method in Section V.MM.5 of this preamble whereby petroleum product suppliers report data that allows EPA to distinguish between the biomass and fossil fuel-based carbon in their products.
In assessing the appropriateness of applying a threshold to refiners (at the facility level) and importers (at the corporate level), we calculated the volume of finished gasoline that would contain enough carbon that, when combusted or oxidized, would produce 1,000 metric tons CO
Based on the calculations in Table MM–1 of this preamble and data on the annual volume of petroleum products that refiners and importers are currently reporting to the EIA, EPA estimated the number of refineries and importers that would meet each of the four selected threshold levels. The results of this analysis are summarized below.
For a full discussion of the threshold analysis, please refer to the Suppliers of Petroleum Products TSD (EPA–HQ–OAR–2008–0508–039). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
Rather than directly measuring emissions from the combustion or consumption of their products, suppliers of petroleum products would need to estimate the potential emissions of their non-crude feedstocks and products based on volume and characteristic information. Therefore product volume metering and sampling would be of utmost importance to accurately calculate potential CO
We propose that all flow meters and tank gauges must be calibrated prior to monitoring under this rule using a method published by a consensus standards organization (e.g., ASTM, ASME, American Petroleum Institute, or NAESB), or using calibration procedures specified by the flow meter manufacturer. Product flow meters and tank gauges would be required to be recalibrated either annually or at the minimum frequency specified by the manufacturer.
We also considered the benefits and disadvantages of using default carbon content factors and of using direct measurements of carbon content. Default CO
Direct measurements would provide the most accurate determination of carbon content. It is relatively expensive, however, to design and implement a program for regular sampling and testing for carbon content across the variety of products produced at refineries. Many products are homogeneous because they must meet “minimum” specifications (e.g., jet fuel), and the use of direct measurements may not lead to noticeable improvements in accuracy over default CO
Based on this information, we are proposing that for purposes of estimating emissions, reporters could either use the default CO
We request comment on this approach. We request comment on whether reporters should be allowed to combine default CO
In addition, we request comment on the appropriateness of the proposed sampling and analysis standards and methods for developing CO
The various approaches to monitoring GHG emissions are elaborated in the Suppliers of Petroleum Products TSD (EPA–HQ–OAR–2008–0508–039).
Under this proposal, we are suggesting methods for estimating data that may be missing from different source categories for various reasons. Petroleum product suppliers would need to estimate any missing data on the amount of petroleum products or NGLs supplied or exported, and the quantity of the crude and non-crude feedstocks, including biomass, consumed. In most cases, the source category would be missing data due to monitoring equipment malfunction or shutdown.
We are proposing that suppliers of petroleum products be required to report the type, volume, and CO
The only GHG required to be reported under proposed 40 CFR part 98, subpart MM is CO
There is substantial trade and transfer of products between refiners, between importers and refiners, and between other parties. The products supplied by one refiner might in some cases serve as the feedstock for another refiner. To avoid double-counting of emissions, we are proposing an elaboration of the mass-balance approach for use by refiners. Under this elaborated approach, to account for the fact that any non-crude feedstock
We are proposing that suppliers report to EPA the types of products and quantities of products sold during the reporting period or otherwise transferred to another facility, in the case of refiners, or corporate entity, in the case of importers and exporters. This information underlies the proposed CO
We are not proposing that petroleum product suppliers collect new information on those petroleum products which may be used or converted by other entities into long-lived products that are not oxidized or combusted, or oxidized slowly over long periods of time (e.g., plastics). A comprehensive and rigorous system for tracking the fate of non-energy petroleum products and their various end-uses is beyond the scope of this rule, and would require a much more burdensome reporting obligation for petroleum product suppliers. However, at some point, we may need to address the question of non-emissive end uses of petroleum products as part of future climate policy development. We request comment on our proposal to require petroleum product suppliers to report the CO
First, we are proposing to require refiners to report information related to biomass that is co-processed with a petroleum feedstock (crude or non-crude) to produce a product that would be supplied to the economy. We propose that refiners report the volume of and estimated CO
Second, in the case where a reporter supplies or exports a petroleum product that is blended with a biomass-based fuel, we are proposing only to require CO
Under this proposal, we are proposing to require reporters to calculate and report CO
However, we have concluded that comparability and consistency in reporting processes across all facilities included in the entire rule is vital, particularly with respect to timing of submission, reporting formats, QA/QC, database management, missing data procedures, transparency and access to information, and recordkeeping. In addition, all refineries would be reporting emissions from petroleum refining processes under proposed 40 CFR part 98, subpart Y. Finally, as noted above, we are requesting readily available information from petroleum product suppliers and do not consider reporting information to more than one Federal agency an undue burden for these industries. We thus considered but are not proposing an option in which EPA obtains facility-specific data for suppliers of petroleum products through access to existing Federal government reporting databases, such as those maintained by EIA. However, in order to reduce the reporting burden placed on industry, we would consider information that refiners and importers already report to EIA with respect to units and frequency, for example, when crafting the reporting requirements for refiners, importers, and exporters under the final rule.
For purposes of this rule, we are interested in minimizing the additional reporting burden on reporters by
We are proposing that reporters under this source category must maintain all of the following records: copies of all reports submitted to EPA under this rule, records documenting the type and quantity of petroleum products and NGLs supplied to or exported from the economy, records documenting the type, characteristics, and quantity of purchased feedstocks, including crude oil, LPGs, biomass, and semi-refined feedstocks, records documenting the CO
These records should contain data directly used to calculate the emissions that are reported and are necessary to enable verification that the CO
This subpart would require reporting by facilities and companies that introduce or supply natural gas and NGLs into the economy (e.g., LDCs). These facilities and companies would report the CO
Combustion and other uses of natural gas are addressed in other subparts, such as proposed 40 CFR part 98, subpart C (General Fuel Stationary Combustion Sources).
Natural gas is a combustible gaseous mixture of hydrocarbons, mostly CH
In addition to being combusted for energy, natural gas is also consumed for non-energy uses in the U.S. The non-energy applications of natural gas are diverse, and include feedstocks for petrochemical production, ammonia, and other products. In 2006, emissions from non-energy uses of natural gas were 138 million metric tons CO
The supply chain for delivering natural gas to consumers is complex, involving producers (i.e., wells), processing plants, storage facilities, transmission pipelines, LNG terminals, and local distribution companies. In developing the proposed rule, we concluded that inclusion of all natural gas suppliers as reporters would not be practical from an administrative perspective, nor would it be necessary for complete coverage of the supply of natural gas. In determining the most appropriate point in the supply chain of natural gas, we applied the following criteria: An administratively manageable number of reporting facilities; complete coverage of natural gas supply as a group of facilities or in combination with facilities reporting under other subparts of this rule; minimal irreconcilable double-counting of natural gas supply; and feasibility of monitoring or calculation methods.
Based on these criteria, we are proposing to include LDCs for deliveries of dry gas, and natural gas processing facilities for the supply of NGLs as reporters under this source category. LDCs receive natural gas from the large transmission pipelines and re-deliver the gas to end users on their systems, or, in some cases, re-deliver the natural gas to other LDCs or even other transmission pipelines. Importantly, LDCs keep records on the amount of natural gas delivered to their customers. In 2006, LDCs delivered about 12.0 trillion cf or 60 percent of the total 19.9 trillion cf delivered to consumers. The balance of the natural gas is delivered directly to large end users in industry and for power generation. Most of these large end users would already be included as reporting facilities for direct GHG emissions because their emissions exceed the respective emissions threshold for their source category.
LDCs meter the amount of gas they receive and meter and bill for the deliveries they make to all end-use customers or other LDCs and pipelines. Some of the end-use customers may be large industrial or electricity generating facilities that would be included under other subparts for direct emissions related to stationary combustion. LDCs already report their total deliveries to DOE as well as to State regulators. There are approximately 1,207 LDCs in the U.S.
Natural gas processing facilities (defined as any facility that extracts or recovers NGLs from natural gas, separates individual components of NGLs using fractionation, or converts one form of natural gas liquid into another form such as butane to isobutene using isomerization process) take raw untreated natural gas from domestic production and strip out the NGLs, and other compounds. The NGLs are then sold, and the processed gas is delivered to transmission pipelines.
We are not proposing that processing plants report supply of dry natural gas to transmission pipelines. While the processing industry in 2006 delivered an estimated 13.8 trillion cf of processed, pipeline quality gas into the pipeline system, an estimated 30 percent of dry natural gas goes directly from production fields to the transmission pipelines, completely by-passing processing plants. In the interest of increasing coverage, we considered but decided not to propose including
We considered but are not proposing to include the approximately 448,641 (in 2006) production wells in the U.S. as covered facilities. Producers routinely monitor production to predict sales, to distribute sales revenues to working interest owners, pay royalties, and pay State severance taxes. These data are reported regularly to State agencies. At the national level, however, inclusion of producers would be administratively difficult and would include many small facilities. EIA collects reports from a subset of larger producers in key States, but relies on State data to develop comprehensive aggregated national statistics.
We considered but are not proposing to include interstate and intrastate pipelines. Pipeline operators transport almost all of the natural gas consumed in the U.S. including both domestically produced and imported natural gas. While there are a relatively modest number of transmission pipelines, approximately 160, and the operators meter flows and report these data to DOE, their inclusion as reporters would introduce significant complications. The U.S. pipeline network is characterized by interconnectivity, in which natural gas moves through multiple pipelines on its way to the consumers. Given the hundreds of receipt and delivery points and the interconnections with a multiplicity of other pipelines, processing plants, LDCs, and end users, a substantial amount of double-counting errors would be introduced. A time- and resource-intensive administrative effort by EPA and reporting companies would be required annually in an attempt to correct this double-counting.
We are also not proposing to include importers of natural gas as reporting facilities. Natural gas is imported by land via transmission pipelines (primarily from Canada), and as LNG via a small number of port terminals (predominantly on the East and Gulf coasts). Imported natural gas ultimately is delivered to consumers by LDCs or sent directly to high volume consumers who would report under other subparts of proposed 40 CFR part 98.
EPA requests comment on the inclusion of LDCs and processing plants, and the exclusion of other parts of the natural gas supply and distribution chain. For additional background information on suppliers of natural gas, please refer to the Suppliers of Natural Gas and NGLs TSD (EPA–HQ–OAR–2008–0508–040).
In developing the reporting threshold for LDCs and natural gas processors, EPA considered emissions-based thresholds of 1,000 metric tons CO
Table NN–1 of this preamble illustrates the LDC emissions and facilities that would be covered under these various thresholds.
We propose to include all LDCs as reporters in this source category. Of the approximate 1,207 LDCs, the 25,000 metric tons CO
Table NN–2 of this preamble illustrates the NGL emissions and number of processing facilities that would be covered under these various thresholds.
We propose there be no reporting threshold for natural gas processing plants. Each natural gas processing plant is already required to report the supply (beginning stocks, receipts, and production) and disposition (input, shipments, fuel use and losses, and ending stocks) of NGLs monthly on EIA Form 816. Processing plants are also required to report the amounts of natural gas processed, NGLs produced, shrinkage of the natural gas from NGLs extraction, and the amount of natural gas used in processing on an annual basis on EIA Form 64A.
For a full discussion of the threshold analysis, please refer to the Suppliers of Natural Gas and NGLs TSD (EPA–HQ–
Under this subpart, we are proposing reporting the amount of natural gas and NGLs produced or supplied to the economy annually, as well as the CO
The only GHG required to be reported under this subpart is CO
We are proposing that LDCs and natural gas processing plants use a mass-balance method to calculate CO
For carbon content, we have prepared two look-up tables listing default CO
Where natural gas processing plants extract and separate individual components of NGLs, the facilities should report carbon content by individual component of the NGLs. In cases where raw NGLs are not separated, the processing plants should report carbon content for the raw NGLs. LDCs and natural gas processing plants can substitute their own values for carbon content provided they are developed according to nationally-accepted ASTM standards for sampling and analysis.
We considered but do not propose an option in which LDCs and natural gas processing plants would be required to sample and analyze natural gas and NGLs periodically to determine the carbon content. Given the close correlation between carbon content and BTU value of natural gas and NGLs, and the availability of BTU information on these products, EPA believes that periodic sampling and analysis would impose a cost on facilities but would not result in improved accuracy of reported emissions values. We request comment on an approach in which natural gas suppliers would be required to develop facility- and batch-specific carbon contents through periodic sampling and analysis. The various approaches to monitoring GHG emissions are elaborated in the Suppliers of Natural Gas and NGLs TSD (EPA–HQ–OAR–2008–0508–040).
EPA has determined that the information to be reported by LDCs and gas processing plants is routinely collected by facilities as part of standard operating practices, and expects that any missing data would be negligible. Typically, natural gas amounts are metered directly at multiple stages, and billing systems require rigorous reconciliation of data. In cases where metered data are not available, reporters may estimate the missing volumes based on contracted maximum daily quantities and known conditions of receipt and delivery during the period when data are missing.
We propose that LDCs and gas processing plants report CO
Natural gas processing plants would report CO
We considered but are not proposing an option in which EPA obtained facility-specific data for natural gas and NGLs through access to existing Federal government reporting databases, such as those maintained by EIA. We have concluded that comparability and consistency in reporting processes across all facilities included in the entire rule is vital, particularly with respect to timing of submission, reporting formats, QA/QC, database management, missing data procedures, transparency and access to information, and recordkeeping. In addition, large natural gas processing plants would already be included as reporting facilities under proposed 40 CFR 98.2(a)(2), therefore there is minimal burden in reporting the additional information proposed under this subpart. Finally, as noted above, we are requesting readily available information from LDCs and natural gas processing facilities, and do not consider reporting information to more than one Federal agency to place an undue burden on these industries.
Records that must be kept include quantity of individual fuels supplied, BTU content, carbon content determined, flow records and/or invoice records for customers with amount of natural gas received, type of customer receiving natural gas (so the disaggregated report by category can be checked), and data for determining carbon content for natural gas processing plants. These records are necessary to enable verification that the GHG monitoring and calculations were done correctly. Records related to the end-user (e.g., ammonia facility) are required to allow us to reconcile data reported by different facilities and entities, and to ensure that coverage of natural gas supply and end-use is comprehensive.
A full list of records that must be retained onsite is included in proposed 40 CFR part 98, subparts A and NN.
The industrial gas supply category includes facilities that produce N
Under the proposed40 CFR part 98, subpart OO, if you produce fluorinated GHGs or N
Fluorinated GHGs are powerful GHGs whose ability to trap heat in the atmosphere is often thousands to tens of thousands times as great as that of CO
HFCs are the most commonly used fluorinated GHGs, they are used primarily as a replacement for ODS in a number of applications, including air-conditioning and refrigeration, foams, fire protection, solvents, and aerosols. PFCs are used in fire fighting and to manufacture semiconductors and other electronics. SF
In 2006, 12 U.S. facilities produced over 350 million metric tons CO
Fluorinated GHGs are imported both in bulk (contained in shipping containers and cylinders) and in products. For further information, see the Bulk Imports and Exports of Fluorinated Gases TSD (EPA–HQ–OAR–2008–0508–042) and the Imports of Fluorinated GHGs in Products TSD (EPA–HQ–OAR–2008–0508–043). EPA estimates that over 110 million metric tons CO
A variety of products containing fluorinated GHGs are imported into the U.S. Imports of particular importance include pre-charged air-conditioning, refrigeration, and electrical equipment and closed-cell foams. Pre-charged air-conditioning and refrigeration equipment contains a full or partial (holding) charge of HFC refrigerant, while pre-charged electrical equipment contains a full or partial charge of SF
We estimate that in 2010, approximately 18 million metric tons CO
Once produced or imported, fluorinated GHGs can have hundreds of millions of downstream emission points. For example, the gases are used in almost all car air conditioners and household refrigerators and in other ubiquitous products and applications. Thus, tracking emissions of these gases from all downstream uses would not be practical.
N
Two companies operate a total of five N
N
Further information on N
Selection of Reporting Facilities and Types of Data to be Reported. Because fluorinated GHGs and N
In developing this proposed rule, we reviewed a number of protocols that track chemical consumption, its components (production, import, export, etc.), or similar quantities. These protocols included EPA's Stratospheric Ozone Protection regulations at 40 CFR part 82, the EU Regulation on Certain Fluorinated Greenhouse Gases (No. 842/2006), the Australian Commonwealth Government Ozone Protection and Synthetic Greenhouse Gas Reporting Program, EPA's Chemical Substances Inventory Update Rule at 40 CFR 710.43, EPA's Acid Rain regulations at 40 CFR part 75, the TRI Program, and the 2006 IPCC Guidelines.
We reviewed these protocols both for their overall scope and for their specific requirements for monitoring and reporting. The monitoring requirements are discussed in Section V.OO.3 of this preamble. The protocols whose scopes were most similar to the one proposed for industrial gas supply were EPA's Stratospheric Protection Program, the EU Regulation on Certain Fluorinated Greenhouse Gases, the Australian Synthetic Greenhouse Gas Reporting Program, and EPA's Chemical Substances Inventory Update Rule. All four of these programs require reporting of production and imports, and the first three also require reporting of exports. In addition, the EU regulation and EPA's Stratospheric Ozone Protection Program require reporting of the quantities of chemicals (ODS) transformed or destroyed. In general, the proposed requirements in this rule are based closely on those in EPA's Stratospheric Ozone Protection Program. By accounting for all chemical flows into and out of the U.S., including destruction and transformation, this approach results in an estimate of consumption that is more closely related to actual U.S. emissions than are estimates of consumption that do not account for all of these flows.
EPA is proposing this definition because HFCs, PFCs, SF
As discussed above, ODS are excluded from the proposed definition of fluorinated GHG because they are already regulated under the Montreal Protocol and Title VI of the CAA.
EPA requests comment on the proposed definition. EPA also requests comment on two other options for defining or refining the set of fluorinated GHGs to be reported. The first option would permit a fluorocarbon to be excluded from reporting if (1) the GWP for the fluorocarbon were not listed in Table A–1 of proposed 40 CFR part 98, subpart A or in any of the IPCC Assessment Reports or World Meteorological Organization (WMO) Scientific Assessments of Ozone Depletion, and (2) the producer or importer of the fluorocarbon could demonstrate, to the satisfaction of the Administrator, that the fluorocarbon had an atmospheric lifetime of less than one year and a 100-year GWP of less than five. In general, we expect that new fluorocarbons would be used in relatively low volumes. For such chemicals, a GWP of five may be a reasonable trigger for reporting.
The second option would be to require reporting only of those fluorinated chemicals listed in Table A–1 of proposed 40 CFR part 98, subpart A. The disadvantage of this approach is that it would exclude any new (or newly important) fluorocarbons whose GWPs have not been evaluated. As discussed above, fluorocarbons in general are likely to have significant GWPs. Given the pace of technological development in this area, production (and emissions) of these gases could become significant before the chemicals were added to the table.
In developing the proposed thresholds for producers and importers of fluorinated GHGs and N
The requirement that all facilities report would simplify the rule and permit facilities to quickly determine whether or not they must report. The one potential drawback of this requirement is that small-scale production facilities (e.g., for research and development) could be inadvertently required to report their production, even though the quantities produced would be small in both absolute and CO
Because it may be relatively easy for importers and exporters to create new corporations in order to divide up their imports and exports and remain below applicable thresholds, we considered setting no threshold for importers and exporters. However, we are not proposing this option because we are concerned that it would be too burdensome to current small-scale importers. We request comment on this approach, specifically the burden on small-scale importers if they were required to report.
Further information on the threshold analysis for industrial gas suppliers can be found in the Suppliers of Industrial GHGs TSD (EPA–HQ–OAR–2008–0508–041). For specific information on costs, including unamortized first year capital expenditures, please refer to section 4 of the RIA and the RIA cost appendix.
If you produce N
If you import or export bulk N
We propose to require reporting of imports and exports in metric tons of chemical because that is the unit in which other quantities (production, emissions, etc.) are proposed to be reported under this rule. However,
In general, these proposed requirements are consistent with those of other programs that monitor imports and exports of bulk chemical, particularly EPA's Stratospheric Ozone Protection regulations.
Existing programs vary in their treatment of products containing chemicals whose bulk import must be reported. The Australian program requires reporting of all ODS and GHGs imported in pre-charged equipment, including the identity of the refrigerant, the number of pieces of equipment, and the charge size. The Inventory Update Rule requires reporting of chemicals contained in products if the chemical is designed to be released from the product when it is used (e.g., ink from a pen). EPA's Stratospheric Ozone Protection regulations do not currently require reporting of ODS contained in imported equipment or other imported products; however, (1) EPA has prohibited the introduction into interstate commerce, including import, of certain non-essential products typically pre-charged with these chemicals, and (2) EPA is in the process of proposing new regulations to prohibit import of equipment pre-charged with HCFCs.
We are not proposing to require that importers of products containing N
Under the proposed rule, if you chemically transform N
Under the proposed rule, if you produce and destroy fluorinated GHGs, you would be required to estimate the quantity of each fluorinated GHG destroyed. This estimate would be based on (1) the quantity of the fluorinated GHG fed into the destruction device, and (2) the DE of the device. In developing the estimate, you would be required to account for any decreases in the DE of the device that occurred when the device was not operating properly (as defined in State or local permitting requirements and/or destruction device manufacturer specifications). Finally, you would be required to perform annual fluorinated GHG concentration measurements by gas chromatography to confirm that emissions from the destruction device were as low as expected based on the DE of the device. If emissions were found to be higher, then you would have the option of using the DE implied by the most recent measurements or of conducting more extensive measurements of the DE of the device.
These proposed requirements are identical to those proposed for destruction of HFC–23 that is generated as a byproduct during HCFC–22 production. They are also similar to those contained in EPA's Stratospheric Ozone Protection Regulations. Those regulations include detailed requirements for reporting and verifying transformation and destruction of chemicals.
We are proposing requirements for verifying the DE of destruction devices used to destroy fluorinated GHGs because fluorinated GHGs, particularly PFCs and SF
We believe that owners or operators of facilities that destroy fluorinated GHGs are already likely to verify the DEs of their destruction devices. Many facilities destroying fluorinated GHGs are likely to destroy ODS as well. In this case, they are already subject to requirements to verify the DEs of their devices.
We request comment on the extent of potential overlap between the destruction reported under proposed 40 CFR part 98, subpart OO and that reported under proposed 40 CFR part 98, subpart L. To obtain an accurate estimate of the net supply of fluorinated industrial greenhouse gases, fluorinated GHGs that are produced and subsequently destroyed should be subtracted from the total produced or imported. However, if fluorinated GHGs are never included in the mass produced (e.g., because they are removed from the production process with or as byproducts), then including them in the mass destroyed would lead to an underestimate of supply. One possible solution to this problem would be to require facilities producing and destroying fluorinated GHGs to separately estimate and report their destruction of fluorinated GHGs that have been counted as produced in either the current year or previously.
EPA is not proposing to require reporting of N
The protocols and guidance reviewed by EPA differ in their level of specificity regarding the measurement of production or other flows, particularly regarding their precision and accuracy requirements. Some programs, such as the Stratospheric Ozone Protection regulations, do not specify any accuracy requirements, while other programs specifically define acceptable errors and reference industry standards for calibrating and verifying monitoring equipment. One of the latter is 40 CFR part 75, Appendix D, which establishes requirements for measuring oil and gas flows as a means of estimating SO
In today's proposed rule, we are proposing to require facilities to measure the mass of N
EPA requests comment on these proposed requirements. EPA specifically requests comment on the proposed frequency of calibration for flowmeters; the Agency understands that some types of flowmeters that are commonly employed in chemical production, such as the Coriolis type, may require less frequent calibration.
We are proposing specific accuracy, precision, and calibration requirements because the high GWPs and large volumes of fluorinated GHGs produced make such requirements worthwhile for this source category. For example, a one percent error at a typical facility producing fluorinated GHGs would equate to 300,000 metric tons CO
EPA is not proposing precision and accuracy requirements for importers and exporters of bulk chemical; however, EPA requests comment on whether such requirements (e.g., 0.5 to 1 percent) would be appropriate.
In the event that any data on the mass produced, fed into the production process (for used material being reclaimed), fed into transformation processes, fed into destruction devices, or sent to another facility for transformation or destruction, is unavailable, we propose that facilities be required to use secondary measurements of these quantities. For example, facilities that ordinarily measure production by metering the flow into the day tank could use the weight of product charged into shipping containers for sale and distribution. We understand that the types of flowmeters and scales used to measure fluorocarbon production (e.g., Coriolis meters) are generally quite reliable, and therefore it should rarely be necessary to rely on secondary production measurements. In general, production facilities rely on accurate monitoring and reporting of production and related quantities.
If concentration measurements were unavailable for some period, we propose that the facility be required to report the average of the concentration measurements from just before and just after the period of missing data.
There is one proposed exception to these requirements: If the facility has reason to believe that either method would result in a significant under- or overestimate of the missing parameter, then the facility would be required to develop an alternative estimate of the parameter and explain why and how it developed that estimate. We would have the option of rejecting this alternative estimate and replacing it with the value developed using the usual missing data method if we did not agree with the rationale or method for the alternative estimate.
We request comment on these methods for estimating missing data. We also request comment on the option of estimating missing production data based on consumption of reactants, assuming complete stoichiometric conversion. This approach could be used in the very unlikely event that neither primary nor secondary direct measures of production were available.
We do not believe that missing data would be a problem for importers and exporters of GHGs due to their requirement to declare the quantities of GHGs imported or exported for Customs purposes. However, we request comment on this assumption.
Under the proposed rule, facilities would be required to submit data, described below, in addition to the production, import, export, feedstock, and destruction data listed above. This data is intended to permit us to check the main estimates submitted. A complete list of data to be reported is included in proposed 40 CFR part 98, subparts A and OO.
Facilities producing N
Importers of N
Exporters of N
These proposed requirements are very similar to those that apply to importers and exporters of ODS under EPA's Stratospheric Ozone Protection Program. We are proposing them because they would provide us with valuable information for verifying the nature and size of GHG imports and exports.
In addition to annually reporting the mass of fluorinated GHG fed into the destruction device, facilities destroying fluorinated GHGs would be required to submit a one-time report including the following: The destruction unit's DE, the methods used to record volume destroyed and to measure and record DE, and the names of other relevant Federal or State regulations that may apply to destruction process. This one-time report is very similar to that required under EPA's Stratospheric Ozone Protection regulations.
EPA is proposing that the following records be retained because they are necessary to verify production, import, export, transformation, and destruction estimates and related quantities and calibrations.
Owners or operators of facilities producing N
Importers of N
Every person who imported a container with a heel would be required to keep records of the amount brought into the U.S. and document that the residual amount in each shipment is less than 10 percent of the net mass of the container when full and would: Remain in the container and be included in a future shipment, be recovered and transformed, or be recovered and destroyed.
Exporters of N
Owners or operators of production facilities using N
Owners or operators of GHG production facilities that destroy fluorinated GHGs would be required to keep records documenting: The information that they send in the one-time and annual reports, the initial and annual calibration of the flowmeters or scales used to measure the mass of GHG fed into the destruction device, the method for tracking startups, shutdowns, and malfunctions and any GHG emissions during these events, and the periodic calibration of gas chromatographs used to annually analyze the concentration of fluorinated GHG in the destruction device exhaust stream, as well as the representativeness of the conditions under which the measurement took place.
CO
To ensure consistent treatment of CO
According to the U.S. GHG Inventory in 2006, the total supply of CO
We seek comment on the decision to exclude the reporting of fugitive CO
We are not proposing the inclusion of geologic sequestration in the proposed rulemaking. However, the Agency recognizes that there may be significant stakeholder interest in reporting the amount of CO
We reviewed a number of existing and proposed methodologies for monitoring and reporting fugitive emissions from carbon capture, transport, injection and storage. A summary of these protocols can be found in the Review of Existing Programs memorandum (EPA–HQ–OAR–2008–0508–054). Based on this review, a possible approach to include geologic sequestration might be to ask EOR operators to submit a geologic sequestration report. This report could provide information on the amount of CO
• The owner and operator of the geologic sequestration site(s). Including the business name, address, contact name, and telephone number.
• Location of the geologic sequestration site(s) including a map showing the modeled aerial extent of the CO
• Permitting information. Including information on the UIC well permit(s) issued by the appropriate State or Federal agency: Permit number or other unique identification, date the permit was issued and modified if applicable, permitting agency, contact name, and telephone number.
• An overview of the site characteristics, referencing or providing information which demonstrates sufficient storage capacity for the expected operating lifetime of the plant and the presence of an effective confining system overlying the injection zone.
• An assessment of the risks of CO
• An overview of the methods used to model the subsurface behavior of CO
• Baseline conditions used to evaluate performance of the site including the amount of naturally occurring CO
• Summary of the monitoring plan that would be used to determine CO
The information listed above could be submitted one time and then updated as appropriate. However, the volume of CO
EPA has identified at least nine industrial facilities or process units in the U.S. that currently capture CO
Under the proposed rule, all industrial facilities that capture and transfer a CO
Based on the volumes of CO
We have concluded that reporting the volume of the CO
Importers and exporters of CO
For additional information on the threshold analysis please refer to the Suppliers of CO
The monitoring plan for CO
We propose to require reporting on the volume of the CO
We conclude that there is minimal incremental burden associated with this approach for CO
We also considered requiring CO
The methods proposed are generally consistent with existing GHG reporting protocols. Although existing protocols focus on accounting for fugitive emissions, and not quantity of CO
Facilities with missing monitoring data on the volume of the CO
Facilities with missing data on the composition of the CO
For CO
EPA proposes to collect data on the measured volume of the CO
Owners or operators of all CO
This section of the preamble describes proposed GHG reporting requirements for manufacturers of new mobile sources, including motor vehicles and engines, nonroad vehicles and engines, and aircraft engines.
Not discussed in this portion of the preamble are proposed GHG reporting requirements related to transportation fuels (see Section V.MM of this preamble, Suppliers of Petroleum Products) and motor vehicle and engine manufacturing facilities (see Section V.C of this preamble, General Stationary Fuel Combustion Sources).
GHGs produced by transportation sources include CO
For the new vehicle and engine manufacturer reporting requirements proposed in this Notice, EPA intends to build on our long-established programs that control vehicle and engine emissions of criteria pollutants including hydrocarbons, NO
Although the new reporting requirements proposed here focus on emission rates from new vehicles and engines, EPA also is very interested in continually updating and improving our understanding of the in-use activity and total emissions from mobile sources. Thus, we are seeking comment on the need to collect in-use travel activity and other emissions-related data from States and local governments and mobile source fleet operators. Section V.QQ.4 of this preamble describes the existing State and local government and fleet operator data that EPA currently collects and requests public comment on the need for, and substance of, additional reporting requirements.
As mentioned above, EPA is proposing GHG reporting requirements that fit within the reporting framework established for EPA's long-established criteria pollutant emissions control programs and vehicle fuel economy testing program. While the details of the programs vary widely among the vehicle and engine categories, EPA generally requires manufacturers to conduct emissions testing and report the resulting emissions data to EPA for approval on an annual basis prior to the introduction of the vehicles or engines into commerce. As a part of this process, since the early 1970s, EPA has collected criteria pollutant emissions data for all categories of vehicles and engines used in the transportation sector, including engines used in nonroad equipment (see Table QQ–1 of this preamble).
For purposes of EPA certification, manufacturers typically group vehicles/engines with similar characteristics into families and perform emission tests on representative or worst-case vehicles/engines from each family. Integral to EPA's existing certification procedures are well-established methods for assuring the completeness and quality of reported emission test data. We are proposing to require manufacturers to measure and report GHG emissions data as part of these current emissions testing and certification procedures. These procedures, appropriate here because of the long-standing history and structure of mobile source control programs, are necessarily different from the monitoring-based methods proposed for other sources elsewhere in this notice.
After a discussion of the proposed small business threshold, the following subsections describe the proposed GHG emissions measurement and reporting requirements for manufacturers. As discussed in those subsections, some manufacturers already measure and report some GHG emissions, some measure but do not have to report GHG emissions, and others would need to measure and report for the first time. We propose that the new measurement and reporting requirements apply beginning with the 2011 model year, although we encourage voluntary measurement and reporting for model year 2010.
In most of EPA's recent mobile source regulatory programs for criteria pollutants, EPA has applied special provisions to small manufacturers. EPA proposes to exempt small manufacturers from the GHG reporting requirements. We define “small business” or “small volume manufacturer” separately for each mobile source category. These definitions were established in the regulations during the rulemaking process for each category, which included consultation with small entities and with the Small Business Administration. We're proposing to use these same definitions in each case for the reporting requirements exemption. We believe that this exemption would avoid the relatively high per-vehicle or per-engine reporting costs for small manufacturers without detracting from the goals of the reporting program, as discussed below.
It is important to note that this “threshold” would differ from the approach proposed for other source categories discussed in Section V of this preamble. That is, EPA would not have manufacturers determine their eligibility based on total tons emitted per year. As discussed above, EPA's current mobile source criteria pollutant control programs are based on emissions rates over prescribed test cycles rather than tons per year estimates. Since we are proposing to build on our existing system, we believe that a threshold based on manufacturer size is appropriate for the mobile source sector. Although the emission rates of some vehicles and engines would not be reported, we do not believe this is a concern because the technologies—and thus emission rates—from larger manufacturers represent the same basic technologies and emission rates of essentially all vehicles and engines. It is also worth noting that the manufacturers that meet the small manufacturer definitions represent a very small fraction of overall vehicle and engine sales. For nine out of the twelve non-aircraft mobile source categories (there are currently no small aircraft engine manufacturers), we estimate that sales from small manufacturers represent less than 10 percent of overall sales (for eight of these categories, including light-duty vehicles, small manufacturers account for less than 3 percent of sales). For the remaining three categories (highway motorcycles, all terrain vehicles/off-road motorcycles, and small spark ignition engines) we estimate that small entities account for less than 32 percent of sales.
Please see the discussion of our compliance with the RFA in Section IX.C of this preamble. We request comments on our proposed approach for the reporting threshold for mobile source categories.
We propose that manufacturers of passenger cars, light trucks, and medium-duty passenger vehicles measure and report emissions of CO
For CH
In the case of N
The current FTP for light-duty vehicles is performed with the A/C turned on only during the SC03, or “air conditioning,” test procedure. This test is used to verify emissions compliance in a “worst-case” situation when the A/C system is operating under relatively extreme conditions. The SC03 is also used in the 5-cycle fuel economy calculation for fuel economy labeling. Thus, although the SC03 test results in a value for CO
In order to provide for consistent, accurate measurement of A/C-related CO
Within each vehicle model type, various configurations of engine and cooling system options can be expected to have somewhat different A/C-related CO
The A/C CO
The additional CO
The proposed A/C CO
The proposed A/C CO
EPA also requests comment on three different approaches that could be used alone or in combination with the proposed A/C CO
Second, EPA is seeking comment on basing reporting requirements on a “bench” test procedure similar to the one being developed by the SAE and the University of Illinois, which was employed to measure A/C efficiency
Finally, EPA is seeking comment on basing reporting requirements on design-based criteria for characterizing A/C-related CO
Under our proposal, each key A/C-related component and system would be assigned an expected rate of refrigerant leakage, in the form of a leakage “score,” in terms of grams per year. These individual scores would be added to result in an overall leakage score for the vehicle. We propose that manufacturers establish an overall leakage score for the same test vehicle(s) on which they run the A/C CO
The cooperative industry and government Improved Mobile Air Conditioning Program referenced above also has developed a comprehensive set of leakage scores that EPA proposes to use to represent the significant sources of A/C refrigerant leakage from newer vehicles. The Improved Mobile Air Conditioning Program and the SAE have established a template for calculating individual leakage scores based on the quantity and type of components, fittings, seals, and hoses utilized in a specific A/C system design; this template is known as the SAE Surface Vehicle Standard J2727. EPA is proposing a set of component and system leakage scores, based closely on J2727, but expanded to place greater emphasis on characterizing leakage emissions later in the vehicle's life. Like the J2727, this proposed EPA protocol would associate each technology or system design approach with a specific leakage score. Each score would be a design-based, “leakage-equivalent” value that would take into account expected early-in-life refrigerant leakage from the specified components and systems. Manufacturers would report this value to EPA on their application for certification.
In addition, we request comment on the whether other A/C design considerations, such as use of alternative refrigerants, monitoring refrigerant leakage (with fault storage and indicators), and minimizing refrigerant quantity, should be used in determining an A/C leakage score.
EPA's highway heavy-duty vehicle and engine emissions testing and certification programs generally cover vehicles above 8,500 pounds Gross Vehicle Weight Rating.
We also propose that highway heavy-duty engine manufacturers measure and report CH
Finally, we also propose that these manufacturers measure and report N
As with CO
However, manufacturers of complete heavy-duty vehicles, unlike heavy-duty engine manufacturers, are generally responsible for installing the vehicle's A/C equipment. For this reason, we propose that these manufacturers be responsible for reporting A/C-related emissions, in exactly the same ways that we are proposing for light-duty manufacturers, as described in Section V.QQ.3.c of this preamble. Thus, we propose that these manufacturers perform the A/C CO
Nonroad diesel engines and nonroad large spark-ignition (generally gasoline-fueled) engines are used in a wide variety of construction, agricultural, and industrial equipment applications. However, these engines are very similar (in terms of design, technology, and certification process) to their counterparts certified for highway operation. Given these similarities, we propose that manufacturers of these engines measure and report CO
Like highway heavy-duty truck and bus manufacturers that use certified engines, nonroad diesel equipment manufacturers install certified engines into their equipment but do not certify their equipment. As with trucks and buses, this equipment is often equipped with A/C systems. While we are not proposing any reporting requirements for nonroad equipment manufacturers, we request comment on the appropriateness, feasibility, and cost of extending some form of the proposed A/C CO
There is a large range of spark-ignition engines in this category including engines used in portable power equipment, snowmobiles, all terrain vehicles, off-highway motorcycles, automotive-based, inboard engines used in marine vessels. For purposes of this proposed reporting rule, we also include highway motorcycles, which are tested as complete vehicles. We are proposing that manufacturers measure and report CO
For CH
Finally, we are proposing that manufacturers also report the cycle-weighted N
We are proposing that manufacturers of locomotive and marine diesel engines—including those who certify “remanufactured” engines—measure and report CO
Since diesel locomotives are subject to “total” hydrocarbon standards (which include CH
We also propose that manufacturers—except for C3 marine—measure and report N
This category comprises turbofan, turbojet, turboprop (turbine-driven propeller), turboshaft (turbine-driven helicopters), and piston propulsion engines for commercial, air taxi, and general aviation aircraft. In the case of turbofan and turbojet engines of rated output (or thrust) greater than 26.7 kilonewtons, manufacturers of these engines are already measuring and recording CO
CH
Since little or no N
Within the mobile source sector, NO
EPA does not currently require manufacturers of piston engines (used in any application) to measure, record or report criteria air pollutant or GHG emissions, and no official FTP exists for these engines.
Travel activity and other emissions-related data from State and local governments and fleet operators are critical to understanding the overall GHG contribution of the mobile source sector. These data serve the important role of reflecting real-world conditions and capturing activity levels (e.g., distance traveled and hours operated) from all vehicles and engines, which can complement data that manufacturers report on expected emissions rates from new vehicles and engines. EPA already receives some in-use data through existing reporting programs. The purpose of this section of the preamble is to describe these existing data sources and to request public comment on the need for additional data. In Section V.QQ.4.a of this preamble, we describe data currently reported by State and local governments, and request comment on the potential benefits of the collection of additional data. In Section V.QQ.4.b of this preamble, we highlight the types of data reported by fleet operators as part of the SmartWay Transport Program or other Federal programs, and request comment on the value of other potential reporting requirements.
Travel activity is a term EPA primarily uses for on-road vehicle activity and includes the number and type of vehicles and the distance they travel. State and local governments collect many types of travel activity data, including VMT by vehicle type and model year, fuel type, and/or functional road class (e.g., limited access highways, arterials with traffic signals, etc.). Other types of emissions-related data include vehicle operation and environmental conditions that can affect emissions during travel, such as idling practices and ambient temperature. Travel activity and other emissions-related data can vary over time, between regions, and between metropolitan and rural areas within a given State. EPA can use these data to evaluate how changes in vehicle
EPA currently collects on-road mobile source data to better understand criteria air pollutant emissions, and some of these data can also be used to understand GHG emissions. For example, States provide VMT data to the Agency through the AERR.
The AERR requires State air agencies to report mobile source data, including VMT data at the county level by roadway type,
In addition to EPA's existing data collection requirements, there are other sources of travel activity and emissions-related data. DOT currently collects statewide VMT data for urban and rural roadway types through its Highway Performance Monitoring System. DOT and DOE also publish statistical reports such as the Census Transportation Planning Package, National Personal Transportation Survey, and the Urban Mobility Study. In the past, the U.S. Census Bureau conducted the Vehicle Inventory and Use Survey, which provided valuable data on the physical and operational characteristics of the nation's private and commercial truck populations.
In light of the existing data available to EPA, the Agency is not proposing any new reporting requirements for State and local governments at this time. However, EPA is interested in requesting comment on several topics.
(1) Should EPA require States, local governments, or other entities to report additional travel activity or emissions-related data beyond what is required under EPA's existing reporting requirements? How would such data be used to inform future climate policy?
(2) What, if any, are the specific gaps in the currently reported travel activity or emissions-related data that are important for understanding on-road mobile source GHG emissions? For example, would it be helpful for EPA to better understand State- or county-level VMT growth rates (e.g., based on VMT data collected over the past five or ten years or other methodology) or emissions data related to the freight sector (e.g., hours of long-duration truck idling or truck data that was previously provided by the Vehicle Inventory and Use Survey)? What is the quality of currently reported State and local VMT data, and should travel activity and emissions-related data quality be improved?
(3) Is it sufficient to collect travel activity or emissions-related data every three years as currently required, or should EPA collect such data on an annual basis, similar to other collections discussed in today's action?
(4) Should EPA consider any threshold(s) for States, local governments, or other entities that must report additional travel activity or other emissions-related data? For example, should additional data be reported only from larger metropolitan areas with more sophisticated transportation systems (e.g., metropolitan planning organizations with an urbanized population of 200,000 or more)?
(5) What nonroad activity data is of most interest for understanding GHG emissions, and should EPA consider any additional requirements for reporting such data beyond what is currently required?
b. Mobile Source Fleet Operator Data
Mobile source fleet operators
EPA believes that one of the most important functions of collecting fleet operator data is to inform operators about their emissions profiles and to shed light on opportunities to reduce emissions through the use of clean technologies, fuels, and operational strategies. Through the SmartWay Transport Partnership program, EPA requires participating truck and rail equipment operators, or “partners,” to report data as part of their voluntary commitment to measure and improve the environmental performance of their fleets. EPA uses this data to evaluate partner performance. Partners report annually on their fuel consumption by fuel type, miles traveled, and tonnage of freight carried. Truck operators also have the option of reporting the configuration and model year of each of their trucks. There is no minimum emissions reporting threshold for either truck or rail operators. EPA requires partners to report their annual data
EPA's Climate Leaders program also requires participating companies that operate mobile sources to report CO
In addition, DOT collects and publicly releases extensive data from rail and aircraft operators. All seven Class I
In light of the existing data available to EPA, the Agency is not proposing mandatory reporting requirements for mobile source fleet operators, but is requesting comments on the need for, and substance of, potential reporting requirements at this time. We request comment on the following questions:
(1) Should fleet operators be required to report to EPA outside of voluntary participation in the SmartWay or Climate Leaders programs? How would this data be used to inform future climate policy?
(2) Are there certain categories of mobile sources that should be included or excluded in potential reporting requirements (e.g., lawn mowers, commercial light-duty vehicles, heavy-duty trucks, rail equipment, aircraft, waterborne vehicles)?
(3) Should one or more minimum emissions thresholds apply based on the mobile source category, and what would be appropriate annual thresholds?
(4) Are there certain categories of fleets that should be included or excluded from potential reporting requirements (e.g., public fleets versus private fleets)?
(5) If reporting requirements were to be introduced, what types of data should operators report (e.g., fuel consumption for estimating CO
(6) What type of data verification or quality control should EPA require in any potential reporting requirements?
(7) For potential reporting requirements, are there preferred emissions quantification methods other than those presented in the SmartWay Freight Logistics Environmental and Energy Tracking model or the Climate Leaders reporting protocol?
This section of the preamble describes the process by which EPA proposes to collect, manage, and disseminate data under the GHG reporting rule.
Section V.B of this preamble describes the proposed establishment of a new reporting system that would accept electronic submissions of GHG emissions and supporting data, quality assure the submissions, store the results, and provide access to the public. The new system would follow Agency standards for design, security, data element and reporting format conformance, and accessibility.
Existing sources that would be affected by the proposed GHG reporting rule may currently report emissions or other data to the Agency (or in some cases States) under other titles of the CAA including Title I (Emission Inventory, SIP, NSPS and NESHAP), Title II (National Emissions Standards Act), Title IV (Acid Rain), Title V (Air Operating Permits) and Title VI (Stratospheric Ozone Protection). EPA intends to develop a reporting scheme that minimizes the burden of stakeholders by integrating the new reporting requirements with existing data collection and data management systems, when feasible. Also, EPA would work with States to ease the burden on reporters to State and Federal systems by harmonizing data management, where possible.
Section VI.B of this preamble further describes the proposal regarding the frequency and timeliness of reporting, the requirement for a Designated Representative certification, and the units of measure for submissions and published results.
Section VI.C of this preamble describes QA that EPA would perform to ensure the completeness, accuracy, and validity of submissions. It also describes the feedback that EPA would provide to emission reporters indicating the results of the electronic data quality checks.
Section VI.D of this preamble discusses publication of data that would be collected under the proposed
If a reporting source already reports GHG emissions data to an existing EPA program, the Agency would make efforts to minimize any additional burden on the sources. Some existing programs, however, have data collection and reporting requirements that are inconsistent with the proposed requirements for the mandatory GHG reporting rule. When it is not feasible to adapt the existing program to collect the appropriate emissions data and supplemental data, EPA proposes to require affected sources to submit the data in the requested format to the new data reporting system for the mandatory GHG reporting rule.
Emission sources may fall into one or more categories:
(1) Reporting sources that use existing data collection and reporting methods and would not be required to report separately to the new data reporting system for the GHG reporting rule.
(2) Reporting sources that use existing data collection and reporting methods but would be required to report the data separately to the new data reporting system for the GHG reporting rule.
(3) Reporting sources that are not currently required to collect and report GHG emissions data to EPA and would be required to report using the new data reporting system for the mandatory GHG reporting rule.
EPA believes that using existing data collection methods and reporting systems, when feasible, to collect data required by this proposed rule would minimize additional burden on sources and the Agency. We seek comment on the use of existing collection methods and reporting systems to collect information required by this proposed rule.
For those sources that do not report GHGs or data used to calculate GHG emissions through an existing reporting system, EPA proposes to develop a new system for emission reporters to submit the required data. The detailed data elements that would be reported and other requirements are specified in Sections III, IV and V of this preamble. In general, reporters using this new method would report annually to the Agency covering each calendar year by March 31 of the following year (e.g., annual emissions for calendar year 2010 would be reported by March 31, 2011.)
The Designated Representative (described in proposed 40 CFR part 98, subpart A and Section IV.G of this preamble) must use an electronic signature device (for example, a PIN or password) to submit a report. If the Designated Representative holds an electronic signature device that is currently used for valid electronic signatures accepted under another Agency program, we propose that the new reporting system would also accept valid electronic signatures executed with that device where feasible. (See 40 CFR 3.10 and the definitions of “electronic signature device” and “valid electronic signature” under 40 CFR 3.3.)
We believe that the Agency's reporting format for a given reporting year could make use of several ID codes—unique codes for a unit or facility. To ensure proper matching between databases, e.g., EPA-assigned facility ID codes and the ORIS (DOE) ID code, and consistency from one reporting year to the next, we are proposing that the reporting system provide each facility with a unique identification code to be specified by the Administrator.
To maintain consistency with existing State-level and Federal-level greenhouse gas programs in the U.S. and internationally, the Agency is proposing that all emission measurements be in the SI, also referred to as metric, units. Data used in calculations and supplemental data for QA could still be submitted in English weights and measures (e.g., mmBtu/hr) but the specific units of measure would be included in the data submission. All emissions data would be submitted to the agency in kg or metric tons per unit of time (per year in most cases, but for a few source categories emissions per hour, day, month, quarter, or other unit of time could also be required).
Under this proposed rule, reporters would submit the quantity of each applicable GHG emitted (or other metric) in two forms. The data would be in the form of quantity of the gas emitted (e.g., metric tons of N
The Agency proposes that affected sources submit the emissions data and supplemental data directly to EPA. The Agency believes this would reduce the burden on reporters and State agencies, provide faster access to national emission data, and facilitate consistent QA.
Under CAA Section 114(b), EPA may delegate the authority to collect emissions data from stationary sources to State agencies provided the State agency can satisfy the procedural requirements. We seek comment on the possibility of delegating the authority to State agencies that request such authority and assessing whether the State agency has procedures that are deemed consistent and adequate with the procedures outlined in this rule. For example, how should EPA determine whether a requesting State agency has “consistent and adequate” procedures?
EPA proposes to require all sources affected by this rule to report in an electronic format to be specified by the Administrator. Advantages of electronic reporting include reduced burden on reporters and EPA staff, greater accuracy because data do not need to be manually entered by EPA staff, enhanced ability to conduct electronic audits to ensure data quality, improved comparability because data would be reported in a consistent format, and improved data availability for EPA and the public.
By not specifying the exact reporting format in the regulatory text, EPA maintains flexibility to modify the reporting format and tools in a timely manner. Changes based on stakeholder comment, implementation experience, and new technology could be executed without regulatory action. EPA has used this approach successfully with existing programs, such as the ARP and the Title VI Stratospheric Ozone Protection Program, facilitating the deployment of new reporting formats and tools that take advantage of technologies (e.g., XML) and reduce the burden on reporters and the Agency. The electronic reports submitted under this rule would also be subject to the provisions of 40 CFR 3.10, specifying EPA systems to which electronic submissions must be made and the requirements for valid electronic signatures.
The new reporting system would include automated checks for data completeness, data quality, and data consistency. Such automated checks are used for many other Agency programs (e.g., ARP).
EPA has established a variety of mechanisms under existing programs to provide feedback to reporters who have submitted data to the Agency. EPA will consider the approaches used by other programs (e.g., electronic confirmations, results of QA checks) and develop appropriate mechanisms to provide feedback to reporters for the GHG reporting rule. The process is largely dependent upon such factors as the type of data being submitted and the manner of data transmission. Regardless of data collection system specifics, the goal is to ensure appropriate transparency and timeliness when providing feedback to submitting entities.
The Agency proposes to publish data submitted or collected under this rulemaking through EPA's Web site, reports, and other formats, with the exception of any CBI data, as discussed in Section I.C of this preamble. This level of transparency would inform the public and facilitate greater data verification and review. Transparency helps to ensure data quality and build public confidence in the data so the data can be used to support the development of potential future climate policies or programs.
EPA proposes to disseminate the data on an annual basis. Under this proposed rule, affected sources would be required to report at least on an annual basis, with some reporting more frequently to existing data reporting programs (e.g., the ARP). The Agency believes it would be appropriate to post or publish data collected under this rule once a year after the reporting deadline. The Agency recognizes the high level of public interest in this data, and proposes to disclose it in a timely manner, while also assuring accuracy.
There are a growing number of programs at the State, Tribe, Territory, and Local level that require emission sources in their respective jurisdictions to monitor and report GHG emissions. These programs would likely still continue because they may be broader in scope or more aggressive in implementation than this proposal. In order to be consistent with and supportive of these programs and to reduce burden on reporters and program agencies, EPA proposes that it share emission data with the exception of any CBI data, as discussed in Section III.C of this preamble, with relevant agencies or approved entities using, where practical, shared tools and infrastructure.
To facilitate implementation and compliance, EPA plans to conduct an active outreach and technical assistance program following publication of the final rule. The primary audience would be potentially affected industries. We intend to develop implementation and outreach materials to help facilities understand if the rule applies to them and explain the reporting requirements and timetables. The program particularly would target industrial, commercial, and institutional sectors that do not routinely deal with air pollution regulations.
Compliance materials could be tailored to the needs of various sectors. These materials might include, for example, compliance guides, brochures, fact sheets, frequently asked question and answer documents, sample reporting forms, and GHG emissions calculating tools. We also are considering a compliance assistance hotline for answering questions and providing technical assistance. (We may also want to consider creating a compliance assistance center (
State and local air pollution control agencies routinely interact with many of the sources that would report under this rule. Further, as mentioned in Section II of this preamble, many States have already implemented or are in the process of implementing mandatory GHG reporting and reduction programs. In fact, many States may have reporting programs that are broader in scope or more aggressive in implementation because those programs are either components of established reduction programs (e.g., cap and trade) or being used to design and inform specific complementary measures (e.g., energy efficiency).
Therefore, State and local agencies will serve an important role in communicating the requirements of the rule and providing compliance assistance. In concert with their routine inspection and other compliance and enforcement activities for other CAA programs, State and local agencies also can assist with educating facilities and assuring compliance at facilities subject to this rule.
As discussed in Section VI of this preamble, CAA section 114(b) allows EPA to delegate to States the authority to implement and enforce Federal rules. At this time, however, EPA does not propose to formally delegate implementation of the rule to State and local agencies. Even without delegation, EPA will work with States to ease burden on reporters to State and Federal systems by harmonizing data management, where possible. Further, as discussed in Section VI of this preamble, EPA is proposing to make the data collected under this rule available to States and other interested parties as soon as possible. For example, the quarterly data reported to EPA under Title IV of the CAA is often available on EPA's Web site within a month after it is reported. Furthermore, we recognize that many States with mandatory reporting programs are members of TCR. In some cases, TCR would provide States support in reporting tools, database management and serve as the ultimate repository for data reported under State programs, after the States have verified the data. Given the leadership many of the States have shown in developing and implementing GHG reporting and reduction programs, EPA is seeking comment on the possibility of delegating the authority to collect data under this rule to State agencies. Overall, we request comments on the role of States in implementing this rule and on how States and EPA could interact in administering the reporting program.
Facilities that fail to report GHG emissions according to the requirements of the proposed rule could potentially be subject to enforcement action by EPA under CAA sections 113 and 203–205. The CAA provides for several levels of enforcement that include administrative, civil, and criminal penalties. The CAA allows for injunctive relief to compel compliance and civil and administrative penalties of up to $32,500 per day.
Deviations from the rule that could ultimately be considered violations include but are not limited to the following:
• Failure to report GHG emissions.
• Failure to collect data needed to estimate GHG emissions.
• Failure to continuously monitor and test as required. Note that merely filling in missing data as specified does not excuse a failure to perform the monitoring or testing.
• Failure to keep records needed to verify GHG emissions estimates.
• Failure to estimate GHG emissions according to the methodology(s) specified in the rule.
• Falsification of reports.
This section of the preamble examines the costs and economic impacts of the proposed rule, including the estimated costs and benefits of the proposed rule, and the estimated economic impacts of the proposed rule on affected entities, including estimated impacts on small entities. Complete detail of the economic impacts of the proposed rule can be found in the text of the regulatory impact analysis (RIA) (EPA–HQ–OAR–2008–0318–002).
EPA estimated costs of complying with the proposed rule for process emissions of GHGs in each affected industrial facility, as well as emissions from stationary combustion sources at industrial facilities and other facilities, and emissions of GHGs from mobile sources. 2006 is the representative year of the analysis in that the annual costs were estimated using the 2006 population of emitting sources. EPA used available industry and EPA data to characterize conditions at affected sources. Incremental monitoring, recordkeeping, and reporting activities were then identified for each type of facility and the associated costs were estimated.
The costs of complying with the proposed rule would vary from one facility to another, depending on the types of emissions, the number of affected sources at the facility, existing monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply with the proposed rule. For some affected facilities, costs include costs to monitor, record, and report emissions of GHGs from production processes and from stationary combustion units. For other facilities, the only emissions of GHGs are from stationary combustion. EPA's estimated costs of compliance are discussed in greater detail below:
• Monitoring (private): Staff hours to operate and maintain emissions monitoring systems.
• Reporting (private): Staff hours to gather and process available data and reporting it to EPA through electronic systems.
• Assuring and releasing data (public): Staff hours to quality assure, analyze, and release reports.
Staff activities and associated labor costs would potentially vary over time. Thus, cost estimates are developed for start-up and first-time reporting, and subsequent reporting. Wage rates to monetize staff time are obtained from the BLS.
For the cost analysis, EPA gathered existing data from EPA, industry trade associations, States, and publicly available data sources (e.g., labor rates from the BLS) to characterize the processes, sources, sectors, facilities, and companies/entities affected. Costs were estimated on a per entity basis and then weighted by the number of entities affected at the 25,000 metric tons CO
To develop the costs for the rule, EPA estimated the number of affected facilities in each source category, the number and types of combustion units at each facility, the number and types of production processes that emit GHGs, process inputs and outputs (especially for monitoring procedures that involve a carbon mass balance), and the measurements that are already being made for reasons not associated with the proposed rule (to allow only the incremental costs to be estimated). Many of the affected sources categories, especially those that are the largest emitters of GHGs (e.g., electric utilities, industrial boilers, petroleum refineries, cement plants, iron and steel production, pulp and paper) are subject to national emission standards and we use data generated in the development of these standards to estimate the number of sources affected by the reporting rule.
Other components of the cost analysis included estimates of labor hours to perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping for other rules; information from the industry characterization on the number of units or process inputs and outputs to be monitored; and engineering judgment by industry and EPA industry experts and engineers. Labor costs were taken from the BLS and adjusted to account for overhead. Monitoring costs were generally based on cost algorithms or approaches that had been previously developed, reviewed, accepted as adequate, and used specifically to estimate the costs associated with various types of measurements and monitoring.
A detailed engineering analysis was conducted for each subpart of the proposed rule to develop unique unit costs. This analysis is documented in the RIA. The TSDs for each source category provide a discussion of the applicable measurement technologies and any existing programs and practices. Section 4 of the RIA contains a description of the engineering cost analysis.
Table VIII–1 of this preamble presents by subpart: The number of entities, the downstream emissions covered, the first year capital costs and the first year annualized costs of the proposed rule. EPA estimates that the total national annualized cost for the first year is $168 million, and the total national annualized cost for subsequent years is $134 million (2006$). Of these costs, roughly 5 percent fall upon the public
The threshold, in large part, determines the number of entities required to report GHG emissions and hence the costs of the rule. The number of entities excluded increases with higher thresholds. Table VIII–2 of this preamble provides the cost-effectiveness analysis for the various thresholds. Three metrics are used to evaluate the cost-effectiveness of the emissions threshold. The first is the average cost per metric ton of emissions reported ($/metric ton CO
Table VIII–3 of this preamble presents costs broken out by upstream and downstream sources. Upstream sources include the fuel suppliers and industrial GHG suppliers. Downstream suppliers include combustion sources, industrial processes, and biological processes. Most upstream facilities (e.g., coal mines, refineries, etc.) are also direct emitters of GHGs and are included in the downstream side of the table. As shown in Table VIII–3 of this preamble, over 99 percent of industrial processes emissions are covered at the 25,000 metric tons CO
EPA prepared an economic impact analysis to evaluate the impacts of the proposed rule on affected industries and economic sectors. In evaluating the various reporting options considered, EPA conducted a cost-effectiveness analysis, comparing the cost per metric ton of GHG emissions across reporting options. EPA used this information to identify the preferred options described in today's proposed rule.
To estimate the economic impacts of the proposed rule, EPA first conducted a screening assessment, comparing the estimated total annualized compliance costs by industry, where industry is defined in terms of North American Industry Classification System (NAICS) code, with industry average revenues. Overall national costs of the rule are significant because there are a large number of affected entities, but per-entity costs are low. Average cost-to-sales ratios for establishments in affected NAICS codes are uniformly less than 0.8 percent.
These low average cost-to-sales ratios indicate that the proposed rule is unlikely to result in significant changes in firms' production decisions or other behavioral changes, and thus unlikely to result in significant changes in prices or quantities in affected markets. Thus, EPA followed its
As required by the RFA and SBREFA, EPA assessed the potential impacts of the proposed rule on small entities (small businesses, governments, and non-profit organizations). (See Section IX.C of this preamble for definitions of small entities.)
EPA believes the proposed thresholds maximize the rule coverage with 85 to 90 percent of U.S. GHG emissions reported by approximately 13,205 reporters, while keeping reporting burden to a minimum and excluding small emitters. Furthermore, many industry stakeholders that EPA met with expressed support for a 25,000 metric ton CO
EPA conducted a screening assessment comparing compliance costs for affected industry sectors to industry-specific receipts data for establishments owned by small businesses. This ratio constitutes a “sales” test that computes the annualized compliance costs of this proposed rule as a percentage of sales and determines whether the ratio exceeds some level (e.g., 1 percent or 3 percent).
EPA was not able to calculate a cost-to-sales ratio for manure management (NAICS 112) as SUSB (SBA, 2008a) data does not provide establishment information for agricultural NAICS codes (e.g., NAICS 112 which covers manure management). EPA estimates that the total first year reporting costs for the entire manure management industry to be $0.2 million with an average cost per ton reported of $0.14.
As shown, the cost-to-sales ratios are less than 1 percent for establishments owned by small businesses that EPA considers most likely to be covered by the reporting program (
EPA acknowledges that several enterprise categories have ratios that exceed this threshold (e.g., enterprise with one to 20 employees). EPA took a conservative approach with the model entity analysis. Although the appropriate SBA size definition should be applied at the parent company (enterprise) level, data limitations allowed us only to compute and compare ratios for a model establishment within several enterprise size ranges. To assess the likelihood that these small businesses would be covered by the rule, we performed several case studies for manufacturing industries where the cost-to-receipt ratio exceeded 1 percent. For each industry, we used and applied emission data from a recent study examining emission thresholds.
The case studies showed two industries (cement and lime manufacturing) where emission rates suggest small businesses of this employment size could potentially be covered by the rule. As a result, EPA examined corporate structures and ultimate parent companies were identified using industry surveys and the latest private databases such as Dun & Bradstreet. The results of this analysis show cost to sales ratios below 1 percent.
For the other enterprise categories identified with ratios between 1 percent and 3 percent EPA examined industry specific bottom up databases and previous industry specific studies to ensure that no entities with less than 20 employees are captured under the rule.
Although this rule would not have a significant economic impact on a substantial number of small entities, the Agency nonetheless tried to reduce the impact of this rule on small entities, including seeking input from a wide range of private- and public-sector stakeholders. When developing the proposed rule, the Agency took special steps to ensure that the burdens imposed on small entities were minimal. The Agency conducted several meetings with industry trade associations to discuss regulatory options and the corresponding burden on industry, such as recordkeeping and reporting. The Agency investigated alternative thresholds and analyzed the marginal costs associated with requiring smaller entities with lower emissions to report. The Agency also recommended a hybrid method for reporting, which provides flexibility to entities and helps minimize reporting costs.
Additional analysis for a model small government also showed that the annualized reporting program costs were less than 1 percent of revenue. These impacts are likely representative of ratios in industries where data limitations do not allow EPA to compute sales tests (e.g., general stationary combustion and manure management). Potential impacts of the proposed rule on small governments were assessed separately from impacts on Federal Agencies. Small governments and small non-profit organizations may be affected if they own affected stationary combustion sources, landfills, or natural gas suppliers. However, the estimated costs under the proposed rule are estimated to be small enough that no small government or small non-profit is estimated to incur significant impacts. For example, from the 2002 Census (in $2006), revenues for small governments (counties and municipalities) with populations fewer than 10,000 are $3 million, and revenues for local governments with populations less than 50,000 is $7 million. As an upper bound estimate, summing typical per-respondent costs of combustion plus landfills plus natural gas suppliers yields a cost of approximately $17,047 per local government. Thus, for the smallest group of local governments (<10,000 people), cost-to-revenue ratio would be 0.8 percent. For the larger group of governments less than 50,000, the cost-to-revenue ratio is 0.3 percent.
EPA examined the potential benefits of the GHG reporting rule. Because the benefits of a reporting system are based on their relevance to policy making, transparency issues, and market efficiency, and therefore benefits would be very difficult to quantify and monetize. Instead of a quantitative analysis of the benefits, EPA conducted a systematic literature review of existing studies including government, consulting, and scholarly reports.
A mandatory reporting system would benefit the public by increased transparency of facility emissions data. Transparent, public data on emissions allows for accountability of polluters to the public stakeholders who bear the cost of the pollution. Citizens, community groups, and labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate directly with polluters to lower emissions, circumventing greater government regulation. Publicly available emissions data also would allow individuals to alter their consumption habits based on the GHG emissions of producers.
The greatest benefit of mandatory reporting of industry GHG emissions to government would be realized in developing future GHG policies. For example, in the EU's Emissions Trading System, a lack of accurate monitoring at the facility level before establishing CO
Benefits to industry of GHG emissions monitoring include the value of having independent, verifiable data to present to the public to demonstrate appropriate environmental stewardship. Such monitoring allows for inclusion of standardized GHG data into environmental management systems, providing the necessary information to achieve and disseminate their environmental achievements.
Standardization would also be a benefit to industry, once facilities invest in the institutional knowledge and systems to report emissions, the cost of monitoring should fall and the accuracy of the accounting should improve. A standardized reporting program would also allow for facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry.
Under section 3(f)(1) of EO 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant
In addition, EPA prepared an analysis of the potential costs and benefits associated with this action. A copy of the analysis is available in Docket No. EPA–HQ–OAR–2008–0508–002 and is briefly summarized in Section VIII of this preamble.
The information collection requirements in this proposed rule have been submitted for approval to the OMB under the Paperwork Reduction Act, 44 U.S.C. 3501
EPA plans to collect complete and accurate economy-wide data on facility-level greenhouse gas emissions. Accurate and timely information on greenhouse gas emissions is essential for informing future climate change policy decisions. Through data collected under this rule, EPA will gain a better understanding of the relative emissions of specific industries, and the distribution of emissions from individual facilities within those industries. The facility-specific data will also improve our understanding of the factors that influence greenhouse gas emission rates and actions that facilities are already taking to reduce emissions. Additionally, EPA will be able to track the trend of emissions from industries and facilities within industries over time, particularly in response to policies and potential regulations. The data collected by this rule will improve EPA's ability to formulate climate change policy options and to assess which industries would be affected, and how these industries would be affected by the options.
This information collection is mandatory and will be carried out under CAA sections 114 and 208. Information identified and marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. However, emissions information collected under CAA sections 114 and 208 cannot be claimed as CBI and will be made public.
The projected cost and hour burden for non-federal respondents is $143 million and 1.63 million hours per year. The estimated average burden per response is 2 hours; the proposed frequency of response is annual for all respondents that must comply with the proposed rule's reporting requirements, except for electricity generating units that are already required to report quarterly under 40 CFR part 75 (EPA Acid Rain Program); and the estimated average number of likely respondents per year is 18,775. The cost burden to respondents resulting from the collection of information includes the total capital cost annualized over the equipment's expected useful life (averaging $20.7 million), a total operation and maintenance component (averaging $22.4 million per year), and a labor cost component (averaging $100.0 million per year). Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the RIA for several reasons:
• ICR costs represent the average cost over the first three years of the rule, but costs are reported elsewhere in the RIA for the first year of the rule and for subsequent years of the rule;
• The costs of reporting electricity purchases have been excluded from the ICR, but are still reported in the RIA, although electricity use reporting has been removed from the proposed rule and EPA is soliciting comment on it (see Section 4.2.2, pg 4–18); and
• The first-year costs of coverage determination, estimated to be $867.60 per facility for approximately 16,800 facilities that ultimately determine they do not have to report, are included in the ICR but not in the RIA (see Section 4.2.2, pg 4–18). These costs, averaged over 3 years, are $4.87 million incurred by an average of 5,613 respondents per year.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, EPA has established a public docket for this rule. Submit any comments related to the ICR to EPA and OMB. See
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The small entities directly regulated by this proposed rule include small businesses across all sectors encompassed by the rule, small governmental jurisdictions and small non-profits. We have determined that some small businesses will be affected because their production processes emit GHGs that must be reported, or because they have stationary combustion units onsite that emit GHGs that must be reported. Small governments and small non-profits are generally affected because they have regulated landfills or stationary combustion units onsite, or because they own a LDC.
For affected small entities, EPA conducted a screening assessment comparing compliance costs for affected industry sectors to industry-specific data on revenues for small businesses. This ratio constitutes a “sales” test that computes the annualized compliance costs of this proposed rule as a percentage of sales and determines whether the ratio exceeds some level (e.g., 1 percent or 3 percent). The cost-to-sales ratios were constructed at the establishment level (average compliance cost for the establishment/average establishment revenues). As shown in Table VIII–5 of this preamble, the cost-
The screening analysis thus indicates that the proposed rule will not have a significant economic impact on a substantial number of small entities. See Table VIII–4 of this preamble for sector-specific results. The screening assessment for small governments compared the sum of average costs of compliance for combustion, local distribution companies, and landfills to average revenues for small governments. Even for a small government owning all three source types, the costs constitute less than 1 percent of average revenues for the smallest category of governments (those with fewer than 10,000 people).
Although this proposed rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA determined appropriate thresholds that reduce the number of small businesses reporting. In addition, EPA is not requiring facilities to install CEMS if they do not already have them. Facilities without CEMS can calculate emissions using readily available data or data that are less expensive to collect such as process data or material consumption data. For some source categories, EPA developed tiered methods that are simpler and less burdensome. Also, EPA is requiring annual instead of more frequent reporting.
Through comprehensive outreach activities, EPA held approximately 100 meetings and/or conference calls with representatives of the primary audience groups, including numerous trade associations and industries that include small business members. EPA's outreach activities are documented in the memorandum, “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” located in Docket No. EPA–HQ–OAR–2008–0508–055. EPA maintains an “open door” policy for stakeholders to provide input on key issues and to help inform EPA's understanding of issues, including thresholds for reporting and greenhouse gas calculation and reporting methodologies.
EPA continues to be interested in the potential impacts of the proposed rule on small entities and welcomes comments on issues related to such impacts.
Title II of the UMRA of 1995 (UMRA), 2 U.S.C. 1531–1538, requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on State, local, and Tribal governments and the private sector.
EPA has developed this regulation under authority of CAA sections 114 and 208. The required activities under this Federal mandate include monitoring, recordkeeping, and reporting of GHG emissions from multiple source categories (e.g., combustion, process, biologic and fugitive). This rule contains a Federal mandate that may result in expenditures of $100 million for the private sector in any one year. As described below, we have determined that the expenditures for State, local, and Tribal governments, in the aggregate, will be approximately $14.1 million per year, based on average costs over the first three years of the rule. Accordingly, EPA has prepared under section 202 of the UMRA a written statement which is summarized below.
Consistent with the intergovernmental consultation provisions of section 204 of the UMRA, EPA initiated an outreach effort with the governmental entities affected by this rule including State, local, and Tribal officials. EPA maintained an “open door” policy for stakeholders to provide input on key issues and to help inform EPA's understanding of issues, including impacts to State, local and Tribal governments. The outreach audience included State environmental protection agencies, regional and Tribal air pollution control agencies, and other State and local government organizations. EPA contacted several States and State and regional organizations already involved in greenhouse gas emissions reporting. EPA also conducted several conference calls with Tribal organizations. For example, EPA staff provided information to tribes through conference calls with multiple Tribal working groups and organizations at EPA and through individual calls with two Tribal board members of TRI. In addition, EPA held meeting and conference calls with groups such as TRI, NACAA, ECOS, and with State members of RGGI, the Midwestern GHG Reduction Accord, and WCI. See the “Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” in Docket No. EPA–HQ–OAR–2008–0508–055 for a complete list of organizations and groups that EPA contacted.
Consistent with section 205 of the UMRA, EPA has identified and considered a reasonable number of regulatory alternatives. EPA carefully examined regulatory alternatives, and selected the lowest cost/least burdensome alternative that EPA deems adequate to address Congressional concerns and to provide a consistent, comprehensive source of information about emissions of GHGs. EPA has considered the costs and benefits of the proposed GHG reporting rule, and has concluded that the costs will fall mainly on the private sector (approximately $131 million), with some costs incurred by State, local, and Tribal governments that must report their emissions (less than $12.4 million) that own and operate stationary combustion units, landfills, or natural gas local distribution companies (LDCs). EPA estimates that an additional 1,979 facilities owned by state, local, or tribal governments will incur approximately $1.7 million in costs during the first year of the rule to make a reporting determination and subsequently determine that their emissions are below the threshold and thus, they are not required to report their emissions. Furthermore, we think it is unlikely that State, local and Tribal governments would begin operating large industrial facilities, similar to those affected by this rulemaking operated by the private sector.
Initially, EPA estimates that costs of complying with the proposed rule will be widely dispersed throughout many sectors of the economy. Although EPA acknowledges that over time changes in the patterns of economic activity may mean that GHG generation and thus reporting costs will change, data are inadequate for projecting these changes. Thus, EPA assumes that costs averaged over the first three years of the program are typical of ongoing costs of compliance. EPA estimates that future compliance costs will total approximately $145 million per year. EPA examined the distribution of these costs between private owners and State, local, and Tribal governments owning GHG emitters. In addition, EPA examined, within the private sector, the impacts on various industries. In general, estimated cost per entity represents less than 0.1% of company sales in affected industries. These costs are broadly distributed to a variety of economic sectors and represent approximately 0.001 percent of 2007 Gross Domestic Product; overall, EPA does not believe the proposed rule will have a significant macroeconomic
EPA does not anticipate that substantial numbers of either public or private sector entities will incur significant economic impacts as a result of this proposed rulemaking. EPA further expects that benefits of the proposed rule will include more and better information for EPA and the private sector about emissions of GHGs. This improved information would enhance EPA's ability to develop sound future climate policies, and may encourage GHG emitters to develop voluntary plans to reduce their emissions.
This regulation applies directly to facilities that supply fuel or chemicals that when used emit greenhouse gases, and to facilities that directly emit greenhouses gases. It does not apply to governmental entities unless the government entity owns a facility that directly emits greenhouse gases above threshold levels such as a landfill or large stationary combustion source. In addition, this rule does not impose any implementation responsibilities on State, local or Tribal governments and it is not expected to increase the cost of existing regulatory programs managed by those governments. Thus, the impact on governments affected by the rule is expected to be minimal.
EO 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications.” “Policies that have Federalism implications” is defined in the EO to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”
This proposed rule does not have Federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in EO 13132. However, for a more detailed discussion about how this proposal relates to existing State programs, please see Section II of this preamble.
This regulation applies directly to facilities that supply fuel or chemicals that when used emit greenhouse gases or facilities that directly emit greenhouses gases. It does not apply to governmental entities unless the government entity owns a facility that directly emits greenhouse gases above threshold levels such as a landfill or large stationary combustion source, so relatively few government facilities would be affected. This regulation also does not limit the power of States or localities to collect GHG data and/or regulate GHG emissions. Thus, EO 13132 does not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comments on this proposed rule from State and local officials.
This proposed rule is not expected to have Tribal implications, as specified in EO 13175 (65 FR 67249, November 9, 2000). This regulation applies directly to facilities that supply fuel or chemicals that when used emit greenhouse gases or facilities that directly emit greenhouses gases. Facilities expected to be affected by the proposed rule are not expected to be owned by Tribal governments. Thus, Executive Order 13175 does not apply to this proposed rule.
Although EO 13175 does not apply to this proposed rule, EPA sought opportunities to provide information to Tribal governments and representatives during development of the rule. In consultation with EPA's American Indian Environment Office, EPA's outreach plan included tribes. EPA conducted several conference calls with Tribal organizations. For example, EPA staff provided information to tribes through conference calls with multiple Indian working groups and organizations at EPA that interact with tribes and through individual calls with two Tribal board members of TCR. In addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page a Tribal newsletter—Tribal Air News—that was distributed to EPA/OAQPS's network of Tribal organizations. EPA gave a presentation on various climate efforts, including the mandatory reporting rule, at the National Tribal Conference on Environmental Management on June 24–26, 2008. In addition, EPA had copies of a short information sheet distributed at a meeting of the National Tribal Caucus. See the “Summary of EPA Outreach Activities for Developing the GHG reporting rule,” in Docket No. EPA–HQ–OAR–2008–0508–055 for a complete list of Tribal contacts.
EPA specifically solicits additional comment on this proposed rule from Tribal officials.
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks.
This proposed rule is not a “significant energy action” as defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, we have concluded that this rule is not likely to have any adverse energy effects. This proposal relates to monitoring, reporting and recordkeeping at facilities that supply fuel or chemicals that when used emit greenhouse gases or facilities that directly emit greenhouses gases and does not impact energy supply, distribution or use. Therefore, we conclude that this rule is not likely to have any adverse effects on energy supply, distribution, or use.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104–113 (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.
This proposed rulemaking involves technical standards. EPA proposes to use more than 40 voluntary consensus
By incorporating voluntary consensus standards into this proposed rule, EPA is both meeting the requirements of the NTTAA and presenting multiple options and flexibility for measuring greenhouse gas emissions.
EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable voluntary consensus standards and to explain why such standards should be used in this regulation.
EO 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S.
EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. This proposed rule does not affect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures.
Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements, Motor vehicle pollution.
Environmental protection, Air pollution control, Aircraft, Incorporation by reference.
Environmental protection, Administrative practice and procedure, Confidential business information, Imports, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Research, Vessels, Warranty.
Environmental protection, Administrative practice and procedure, Confidential business information, Imports, Labeling, Reporting and recordkeeping requirements, Research, Warranty.
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Imports, Incorporation by reference, Labeling, Penalties, Vessels, Reporting and recordkeeping requirements, Warranties.
Environmental protection, Administrative practice and procedure, Greenhouse gases, Incorporation by reference, Suppliers, Reporting and recordkeeping requirements.
Administrative practice and procedure, Electric power, Fuel economy, Incorporation by reference, Labeling, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Confidential business information, Incorporation by reference, Labeling, Penalties, Railroads, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Imports, Incorporation by reference, Labeling, Penalties, Reporting and recordkeeping requirements, Warranties.
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Imports, Incorporation by reference, Labeling, Penalties, Vessels, Reporting and recordkeeping requirements, Warranties.
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Imports, Incorporation by reference, Labeling, Penalties, Reporting and recordkeeping requirements, Warranties.
Environmental protection, Administrative practice and procedure, Incorporation by reference, Reporting and recordkeeping requirements, Research.
For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows:
1. The authority citation for part 86 continues to read as follows:
42 U.S.C. 7401–7671q.
2. Section 86.007–23 is amended by adding paragraph (n) to read as follows:
(n) Starting in the 2011 model year for heavy-duty engines, measure CO
(1) Round CO
(2) Round N
(3) Round CH
3. Section 86.078–3 is amended by removing the paragraph (a) designation and adding the abbreviations CH
CH
N
4. A new § 86.165–11 is added to read as follows:
(a)
(b)
(c)
(1) Connect the vehicle exhaust system to the raw sampling location or dilution stage according to 40 CFR 1065.130. For dilution systems, dilute the exhaust as described in 40 CFR 1065.140. Continuous sampling systems must meet the specifications of 40 CFR 1065.145.
(2) Test the vehicle in a fully warmed-up condition. If the vehicle has soaked for two hours or less since the last exhaust test element, preconditioning may consist of a 505, 866, highway, US06, or SC03 test cycle. For longer soak periods, precondition the vehicle using one full Urban Dynamometer Driving Schedule.
(3) Immediately after the preconditioning described in paragraph (c)(1) of this section, turn off any cooling fans, if present, close the vehicle's hood, fully close all the vehicle's windows, ensure that all the vehicle's climate control systems are set to full off, start the CO
(4) Measure and record the continuous CO
(5) Within 60 seconds after completing the measurement described in paragraph (c)(4) of this section, turn on the vehicle's air conditioning system. Set automatic systems to a temperature 9 °F (5 °C) below the ambient temperature of the test cell. Set manual systems to maximum cooling with recirculation turned off. Continue idling the vehicle while measuring and recording the continuous CO
(d)
(2) For the measurement with air conditioning in operation, calculate the CO
(3) Calculate the increased CO
(4) Divide the value from paragraph (d)(3) of this section by the interior volume of the vehicle to determine the increase in CO
(e)
5. Section 86.403–78 is amended by adding the abbreviations CH
CH
N
6. Section 86.431–78 is amended by adding paragraph (e) to read as follows:
(e) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
7. Section 86.1804–01 is amended by adding the abbreviations CH
CH
N
8. Section 86.1843–01 is amended by adding paragraph (i) to read as follows:
(i)
(1) Compressor type (e.g., belt driven or electric).
(2) Number and type of rigid pipes and method of connecting sections of rigid pipes.
(3) Number and type of flexible hose and method of connecting sections of flexible hose. Consider two hoses to be of a different type if they use different materials or if they have a different configuration of layers for reducing permeation.
(4) Number of high-side service ports.
(5) Number of low-side service ports.
(6) Number and type of switches, transducers, and expansion valves.
(7) Number and type of refrigerant control devices.
(8) Number and type of heat exchangers, mufflers, receiver/driers, and accumulators.
(9) The following quantitative criteria (based on nominal values) define operating characteristics for including air conditioning systems together:
(i) Refrigerant mass (rated capacity) of larger system divided by refrigerant mass of smaller system at or below 1.1.
(ii) Total length of rigid pipe in the longer system divided by total length of rigid pipe in the shorter system at or below 1.1.
(iii) Total length of flexible hose in the longer system divided by total length of flexible hose in the shorter system at or below 1.1.
9. Section 86.1844–01 is amended by adding paragraph (j) to read as follows:
(j) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
10. The authority citation for part 87 is revised to read as follows:
42 U.S.C. 7401–7671q.
11. Section 87.2 is amended by adding the abbreviations CH
CH
CO
12. Section 87.64 is revised to read as follows:
(a) The system and procedures for sampling and measurement of gaseous emissions shall be as specified by Appendices 3 and 5 to ICAO Annex 16 (incorporated by reference in § 87.8).
(b) Starting in the 2011 model year, measure CH
(1) Round CO
(2) Round CH
13. The authority citation for part 89 continues to read as follows:
42 U.S.C. 7401–7671q.
14. Section 89.3 is amended by adding the abbreviations CH
CH
N
15. Section 89.115 is amended by revising paragraph (d)(9) to read as follows:
(d) * * *
(9) All test data obtained by the manufacturer on each test engine, including CO
16. Section 89.407 is amended by revising paragraph (d)(1) to read as follows:
(d) * * *
(1) Measure HC, CO, CO
(i) Round CO
(ii) Round N
(iii) Round CH
17. The authority citation for part 90 continues to read as follows:
42 U.S.C. 7401–7671q.
18. Section 90.5 is amended by adding the abbreviations CH
CH
N
19. Section 90.107 is amended by revising paragraph (d)(8) to read as follows:
(d) * * *
(8) All test data obtained by the manufacturer on each test engine, including CO
20. Section 90.409 is amended by revising paragraph (c)(1) to read as follows:
(c) * * *
(1) Measure HC, CO, CO
(i) Round CO
(ii) Round N
(iii) Round CH
21. The authority citation for part 94 continues to read as follows:
42 U.S.C. 7401–7671q.
22. Section 94.3 is amended by adding the abbreviations CH
CH
N
22. Section 94.104 is amended by adding paragraph (e) to read as follows:
(e) Measure CO
23. Section 94.109 is amended by adding paragraph (d) to read as follows:
24. Section 94.203 is amended by revising paragraph (d)(10) to read as follows:
(d) * * *
(10) All test data obtained by the manufacturer on each test engine, including CO
25. Add part 98 to read as follows:
42 U.S.C. 7401,
(a) This part establishes mandatory greenhouse gas (GHG) emissions reporting requirements for certain facilities that directly emit GHG as well as for fossil fuel suppliers and industrial GHG suppliers.
(b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of subpart A and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the subparts B through PP of this part shall take precedence.
(a) The GHG emissions reporting requirements, and related monitoring, recordkeeping, and verification requirements, of this part apply to the owners and operators of any facility that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:
(1) A facility that contains any of the source categories listed in this paragraph in any calendar year starting in 2010. For these facilities, the GHG emission report must cover all sources in any source category for which calculation methodologies are provided in subparts B through JJ of this part.
(i) Electricity generating facilities that are subject to the Acid Rain Program, or that contain electric generating units that collectively emit 25,000 metric tons CO
(ii) Adipic acid production.
(iii) Aluminum production.
(iv) Ammonia manufacturing.
(v) Cement production.
(vi) Electronics—Semiconductor, microelectricomechanical system (MEMS), and liquid crystal display (LCD) manufacturing facilities with an annual production capacity that exceeds any of the thresholds listed in this paragraph.
(A) Semiconductors: 1,080 m
(B) MEMS: 1,020 m
(C) LCD: 235,700 m
(vii) Electric power systems that include electrical equipment with a total nameplate capacity that exceeds 17,820 lbs (7,838 kg) of SF
(viii) HCFC–22 production.
(ix) HFC–23 destruction processes that are not collocated with a HCFC–22 production facility and that destroy more than 2.14 metric tons of HFC–23 per year.
(x) Lime manufacturing.
(xi) Nitric acid production.
(xii) Petrochemical production.
(xiii) Petroleum refineries.
(xiv) Phosphoric acid production.
(xv) Silicon carbide production.
(xvi) Soda ash production.
(xvii) Titanium dioxide production.
(xviii) Underground coal mines that are subject to quarterly or more frequent sampling by MSHA of ventilation systems.
(xix) Municipal landfills that generate CH
(xx) Manure management systems that emit CH
(2) Any facility that emits 25,000 metric tons CO
(i) Electricity generation.
(ii) Electronics—photovoltaic manufacturing.
(iii) Ethanol production.
(iv) Ferroalloy production.
(v) Fluorinated greenhouse gas production.
(vi) Food processing.
(vii) Glass production.
(viii) Hydrogen production.
(ix) Iron and steel production.
(x) Lead production.
(xi) Magnesium production.
(xii) Oil and natural gas systems.
(xiii) Pulp and Paper Manufacturing.
(xiv) Zinc production.
(xv) Industrial landfills.
(xvi) Wastewater treatment.
(3) Any facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). For these facilities, the GHG emission report must cover emissions from stationary fuel combustion sources only. For 2010 only, the facilities may submit an abbreviated emissions report according to § 98.3(d).
(i) The facility does not contain any source category designated in paragraphs (a)(1) and (2) of this section.
(ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater.
(iii) The facility emits 25,000 metric tons CO
(4) Any supplier of any of the products listed in this paragraph (a)(4) in any calendar year starting in 2010. For these suppliers, the GHG emissions report must cover all applicable products for which calculation methodologies are provided in subparts KK through PP of this part.
(i) Coal.
(ii) Coal-based liquid fuels.
(iii) Petroleum products.
(iv) Natural gas and natural gas liquids.
(v) Industrial greenhouse gases, as specified in either paragraph (a)(4)(v)(A) or (B) of this section:
(A) All producers of industrial greenhouse gases.
(B) Importers of industrial greenhouse gases with total bulk imports that exceed 25,000 metric tons CO
(C) Exporters of industrial greenhouse gases with total bulk exports that exceed 25,000 metric tons CO
(vi) Carbon dioxide, as specified in either paragraph (a)(4)(vi)(A) or (B) of this section.
(A) All producers of carbon dioxide.
(B) Importers of CO
(C) Exporters of CO
(b) To calculate GHG emissions for comparison to the 25,000 metric ton CO
(1) Estimate the annual emissions of CO
(2) For stationary combustion units, calculate the annual CO
(3) For miscellaneous uses of carbonate, calculate the annual CO
(4) Sum the emissions estimates from paragraphs (b)(1), (2), and (3) of this section for each GHG and calculate metric tons of CO
(5) For purpose of determining if an emission threshold has been exceeded, capture of CO
(c) To calculate GHG emissions for comparison to the 25,000 metric ton CO
(d) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(1) Calculate the mass in metric tons per year of CO
(2) Convert the mass of each GHG imported and each GHG exported from paragraph (d)(1) of this section to metric tons of CO
(3) Sum the total annual metric tons of CO
(e) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records to determine whether the threshold has been exceeded.
(f) Except as provided in paragraph (g) of this section, the owners and operators of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section are not required to submit an emission report for the facility or supplier. Such owners and operators must reevaluate the applicability to this part to the facility or supplier (which reevaluation must include the revising of any relevant emissions calculations or other calculations) whenever there is any change to the facility or supplier that could cause the facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.
(g) Once a facility or supplier is subject to the requirements of this part, the owners and operators of the facility or supply operation must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit GHG emission reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year. If a GHG emission source in a future year through change of ownership becomes part of a different facility that has not previously met, and does not in that future year meet, the applicability requirements of paragraph (a) of this section; the owner or operator shall comply with the requirements of this part only with regard to that source, including the requirement to submit GHG emission reports.
(h) Table A–2 of this subpart provides a conversion table for some of the common units of measure used in part 98.
The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG emissions reports to the Administrator, as specified in paragraphs (a) through (g) of this section.
(a)
(b)
(1) For existing facilities that commenced operation before January 1, 2010, you must report emissions for calendar year 2010 and each subsequent calendar year.
(2) For new facilities that commence operation on or after January 1, 2010, you must report emissions for the first calendar year in which the facility operates, beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, you must report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(c)
(1) Facility name or supplier name (as appropriate), street address, physical address, and Federal Registry System identification number.
(2) Year covered by the report.
(3) Date of submittal.
(4) Annual emissions of CO
(i) Total facility emissions aggregated from all applicable source categories in subparts C through JJ of this part and expressed in metric tons of CO
(ii) Total emissions aggregated from all applicable supply categories in subparts KK through PP of this part and expressed in metric tons of CO
(iii) Emissions from each applicable source category or supply category in subparts C through PP of this part, expressed in metric tons of each GHG.
(iv) Emissions and other data for individual units, processes, activities, and operations as specified for each source category in the “Data reporting requirements” section of each applicable subpart of this part.
(5) Total electricity generated onsite in kilowatt hours.
(6) Total pounds of synthetic fertilizer produced at the facility and total nitrogen contained in that fertilizer.
(7) Total annual mass of CO
(8) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1).
(d)
(1) Facility name, street address, physical address, and Federal Registry System identification number.
(2) The year covered by the report.
(3) Date of submittal.
(4) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any appropriate method specified in § 98.33(a) and expressed in metric tons of CO
(5) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1).
(e)
(f)
(g)
(1) A list of all units, operations, processes, and activities for which GHG emission were calculated.
(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. The results of all required fuel analyses for high heat value and carbon content, the results of all required certification and quality assurance tests of continuous monitoring systems and fuel flow meters if applicable, and analytical results for the development of site-specific emissions factors.
(3) Documentation of the process used to collect the necessary data for the GHG emissions calculations.
(4) The GHG emissions calculations and methods used.
(5) All emission factors used for the GHG emissions calculations.
(6) Any facility operating data or process information used for the GHG emission calculations.
(7) Names and documentation of key facility personnel involved in calculating and reporting the GHG emissions.
(8) The annual GHG emissions reports.
(9) A log book, documenting procedural changes (if any) to the GHG emissions accounting methods and changes (if any) to the instrumentation critical to GHG emissions calculations.
(10) Missing data computations.
(11) A written quality assurance performance plan (QAPP). Upon request from regulatory authorities, the owner or operator shall make all information that is collected in conformance with the QAPP available for review during an audit. Electronic storage of the information in the QAPP is permissible, provided that the information can be made available in hard copy upon request during an audit. At a minimum, the QAPP plan shall include (or refer to separate documents that contain) a detailed description of the procedures that are used for the following activities:
(i) Maintenance and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHG emissions reported under this part. A maintenance log shall be kept.
(ii) Calibrations and other quality assurance tests performed on the continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHG emissions reported under this part.
(a)
(b)
(c)
(d)
(e)
(1) Each such submission shall include the following certification statement by the designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility (or supply operation, as appropriate) for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) The Administrator will accept a GHG emission report or other submission under this part only if the submission is signed and certified in accordance with paragraph (e)(1) of this section.
(f)
(1) Upon receipt by the Administrator of a complete certificate of representation under this section, any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative.
(2) Except in this section, whenever the term “designated representative” is used, the term shall be construed to include the designated representative or any alternate designated representative.
(g)
(h)
(i)
(1) Identification of the facility or supply operation for which the certificate of representation is submitted.
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the facility or supply operation.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators that are subject to the requirements of 40 CFR 98.3.”
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the Mandatory Greenhouse Gas Reporting Program on behalf of the owners and operators that are subject to the requirements of 40 CFR 98.3 and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.”
(iii) “I certify that the owners and operators that are subject to the requirements of 40 CFR 98.3 shall be bound by any order issued to me by the Administrator or a court regarding the source or unit.”
(iv) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a facility (or supply operation as appropriate) that is subject to the requirements of 40 CFR 98.3, I certify that I have given a written notice of my selection as the `designated representative' or `alternate designated representative', as applicable, and of the agreement by which I was selected to
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(j)
(k)
(l)
(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.
Each GHG emissions report for a facility or supplier must be submitted electronically on behalf of the owners and operators of that facility or supplier by their designated representative, in a format specified by the Administrator.
All terms used in this part shall have the same meaning given in the Clean Air Act and in this section.
DE = Destruction Efficiency
Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized
(1) Off-loading used or excess fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing,
(2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin, and
(3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention.
(1) The consignee.
(2) The importer of record.
(3) The actual owner.
(4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred.
(1) The equipment is attached to a foundation.
(2) The equipment or a replacement resides at the same location for more than 12 consecutive months.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year.
(4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition.
The materials listed in this section are incorporated by reference for use in this part and are incorporated as they existed on the date of approval of this part.
(a) The following materials are available for purchase from the following addresses: American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959; and the University Microfilms International, 300 North Zeeb Road, Ann Arbor, Michigan 48106:
(1) ASTM D240–02, (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter.
(2) ASTM D388–05, Standard Classification of Coals by Rank.
(3) ASTM D396–08, Standard Specification for Fuel Oils.
(4) ASTM D975–08, Standard Specification for Diesel Fuel Oils.
(5) ASTM D1250–07, Standard Guide for Use of the Petroleum Measurement Tables.
(6) ASTM D1826–94 (Reapproved 2003), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter.
(7) ASTM Specification D1835–05 (2005).
(8) ASTM D1945–03 (Reapproved 2006), Standard Test Method for Analysis of Natural Gas by Gas Chromatography.
(9) ASTM D1946–90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography.
(10) ASTM D2013–07, Standard Practice of Preparing Coal Samples for Analysis.
(11) ASTM D2234/D2234M–07, Standard Practice for Collection of a Gross Sample of Coal.
(12) ASTM D2502–04 (Reapproved 2002), Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements.
(13) ASTM D2503–92 (Reapproved 2007), Standard Test Method for Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure.
(14) ASTM D2880–03, Standard Specification for Gas Turbine Fuel Oils.
(15) ASTM D3176–89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke.
(16) ASTM D3238–95 (Reapproved 2005), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method.
(17) ASTM D3588–98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels.
(18) ASTM Specification D3699–07, Standard Specification for Kerosene.
(19) ASTM D4057–06, Standard Practice for Manual Sampling of Petroleum and Petroleum Products.
(20) ASTM D4809–06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method).
(21) ASTM Specification D4814–08a, Standard Specification for Automotive Spark-Ignition Engine Fuel.
(22) ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion.
(23) ASTM D5291–02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants.
(24) ASTM D5373–08, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke.
(25) ASTM D5865–07a, Standard Test Method for Gross Calorific Value of Coal and Coke.
(26) ASTM D6316–04, Standard Test Method for the Determination of Total, Combustible and Carbonate Carbon in Solid Residues from Coal and Coke.
(27) ASTM D6866–06a, Standard Test Methods for Determining the Biobased Content of Natural Range Materials Using Radiocarbon and Isotope Ratio Mass Spectrometry Analysis.
(28) ASTM E1019–03, Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and Cobalt Alloys.
(29) ASTM E1915–07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry.
(30) ASTM CS–104 (1985), Carbon Steel of Medium Carbon Content.
(31) ASTM D 7459–08, Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources.
(32) ASTM D6060–96(2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph.
(33) ASTM D 2502–88(2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography.
(34) ASTM C25–06 Standard Test Method for Chemical Analysis of Limestone, quicklime, and Hydrated Lime.
(35) UOP539–97 Refinery Gas Analysis by Gas Chromatography.
(b) The following materials are available for purchase from the American Society of Mechanical
(1) ASME MFC–3M–2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi.
(2) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters.
(3) ASME-MFC–5M–1985, (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters.
(4) ASME MFC–6M–1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters.
(5) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles.
(6) ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method.
(c) The following materials are available for purchase from the American National Standards Institute (ANSI), 25 West 43rd Street, Fourth Floor, New York, New York 10036:
(1) ISO 8316: 1987 Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank.
(2) ISO/TR 15349–1:1998, Unalloyed steel—Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation).
(3) ISO/TR 15349–3: 1998, Unalloyed steel—Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating).
(d) The following materials are available for purchase from the following address: Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143:
(1) GPA Standard 2172–96, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis.
(2) GPA Standard 2261–00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.
(e) The following American Gas Association materials are available for purchase from the following address: ILI Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652:
(1) American Gas Association Report No. 3: Orifice Metering of Natural Gas, Part 1: General Equations and Uncertainty Guidelines (1990), Part 2: Specification and Installation Requirements (1990).
(2) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (2006).
(f) The following materials are available for purchase from the following address: American Petroleum Institute, Publications Department, 1220 L Street, NW., Washington, DC 20005–4070:
(1) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 3—Tank Gauging:
(i) Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005.
(ii) Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition June 2001 (Reaffirmed, October 2006).
(iii) Section 3—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June 1996 (Reaffirmed, October 2006).
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992).
(3) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 4—Proving Systems:
(i) Section 2—Displacement Provers, Third Edition, September 2003.
(ii) Section 5—Master-Meter Provers, Second Edition, May 2000 (Reaffirmed, August 2005).
(4) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 22—Testing Protocol, Section 2—Differential Pressure Flow Measurement Devices, First Edition, August 2005.
(g) The following material is available for purchase from the following address: American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc., 1791 Tullie Circle, NE., Atlanta, Georgia 30329.
(1) ASHRAE 41.8–1989: Standard Methods of Measurement of Flow of Liquids in Pipes Using Orifice Flowmeters.
Any violation of the requirements of this part shall be a violation of the Clean Air Act. A violation includes, but is not limited to, failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emission, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation.
(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, combustion turbines, engines, incinerators, and process heaters.
(b) This source category does not include portable equipment or generating units designated as emergency generators in a permit issued by a state or local air pollution control agency.
You must report GHG emissions under this subpart if your facility contains one or more stationary combustion sources and the facility meets the requirements of either
You must report CO
The owner or operator shall use the methodologies in this section to calculate the GHG emissions from stationary fuel combustion sources, except for electricity generating units that are subject to the Acid Rain Program. The GHG emissions calculation methods for Acid Rain Program units are addressed in subpart D of this part.
(a)
(1)
(2)
(i) Equation C–2a of this section applies to any type of fuel, except for municipal solid waste (MSW):
(ii) In Equation C–2a of this section, the value of “n” depends upon the frequency at which high heat value (HHV) measurements are required under § 98.34(c). For example, for natural gas, which requires monthly sampling and analysis, n = 6 if the unit combusts natural gas in only 6 months of the year.
(iii) For MSW combustion, use Equation C–2b of this section:
(3)
(i) For a solid fuel, use Equation C–3 of this section:
(ii) For a liquid fuel, use Equation C–4 of this section:
(iii) For a gaseous fuel, use Equation C–5 of this section:
(iv) In applying Equation C–5 of this section to natural gas combustion, the CO
(4)
(i) This methodology requires a CO
(ii) When the CO
(iii) If the CO
(iv) An oxygen (O
(v) Each hourly CO
(vi) The hourly CO
(vii) If both biogenic fuel and fossil fuel are combusted during the year, determine the biogenic CO
(b)
(1) The Tier 1 Calculation Methodology may be used for any type of fuel combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less, provided that:
(i) An applicable default CO
(ii) The owner or operator does not perform, or receive from the entity supplying the fuel, the results of fuel sampling and analysis on a monthly (or more frequent) basis that includes measurements of the HHV. If the owner or operator performs such fuel sampling and analysis or receives such fuel sampling and analysis results, the Tier 1 Calculation Methodology shall not be used, and the Tier 2, Tier 3, or Tier 4 Calculation Methodology shall be used instead.
(2) The Tier 1 Calculation Methodology may also be used to calculate the biogenic CO
(3) The Tier 2 Calculation Methodology may be used for any type of fuel combusted in any unit with a maximum rated heat input capacity of
(4) The Tier 3 Calculation Methodology may be used for a unit of any size, combusting any type of fuel, except when the use of Tier 4 is required or elected, as provided in paragraph (b)(5) of this section.
(5) The Tier 4 Calculation Methodology:
(i) May be used for a unit of any size, combusting any type of fuel.
(ii) Shall be used for a unit if:
(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 250 tons per day of MSW.
(B) The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel.
(C) The unit has operated for more than 1,000 hours in any calendar year since 2005.
(D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit's operating permit.
(E) The installed CEMS include a gas monitor of any kind, a stack gas volumetric flow rate monitor, or both and the monitors have been certified in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program.
(F) The installed gas and/or stack gas volumetric flow rate monitors are required, by an applicable Federal or State regulation or the unit's operating permit, to undergo periodic quality assurance testing in accordance with appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program.
(iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 250 tons of MSW per day or less, if the unit:
(A) Has both a stack gas volumetric flow rate monitor and a CO
(B) The unit meets the other conditions specified in paragraphs (b)(5)(ii)(B) and (C) of this section.
(C) The CO
(6) The Tier 4 Calculation Methodology, if selected or required, shall be used beginning on:
(i) January 1, 2010, for a unit is required to report CO
(ii) January 1, 2011, for a unit that is required to report CO
(c)
(1) For units subject to the requirements of the Acid Rain Program and for other units monitoring and reporting heat input on a year-round basis according to § § 75.10(c) and 75.64 of this chapter, use Equation C–8 of this section:
(2) For all other units, use the applicable equations and procedures in paragraphs (c)(2) through (4) of this section to calculate the annual CH
(i) If a default high heat value for a particular fuel is specified in Table C–1 of this subpart and if the HHV is not measured or provided by the entity supplying the fuel on a monthly (or more frequent) basis throughout the year, use Equation C–9 of this section:
(ii) If the high heat value of a particular fuel (except for municipal solid waste) is measured on a monthly (or more frequent) basis throughout the year, or if such data are provided by the entity supplying the fuel, use Equation C–10a of this section:
(iii) For municipal solid waste combustion, use Equation C–10b of this section to estimate CH
(3) Multiply the result from Equations C–8, C–9, C–10a, or C–10b of this section (as applicable) by the global warming potential (GWP) factor to convert the CH
(4) If, for a particular type of fuel, default CH
(d)
(2) The total annual CO
(e)
(1) The owner or operator may use Equation C–1 of this section to calculate the annual CO
(i) The Tier 4 calculation methodology is not required or elected.
(ii) The biogenic fuel consists of wood, wood waste, or other biomass-derived solid fuels (except for MSW).
(2) If CEMS are used to determine the total annual CO
(i) For each operating hour, use Equation C–12 of this section to determine the volume of CO
(ii) Sum all of the hourly V
(iii) Calculate the annual volume of CO
(iv) Subtract V
(v) Calculate the biogenic percentage of the annual CO
(vi) Calculate the annual biogenic CO
(3) For a unit that combusts MSW, the owner or operator shall use, for each quarter, ASTM Methods D 6866–06a and D 7459–08, as described in § 98.34(f), to determine the relative proportions of biogenic and non-biogenic CO
(i) If the unit qualifies for the Tier 2 or Tier 3 Calculation Methodology of this section and the owner or operator elects to use the Tier 2 or Tier 3 Calculation Methodology to quantify GHG emissions:
(A) Use Equations C–2a, C–2b and C–3 of this section, as applicable, to calculate the annual CO
(B) Determine the annual biogenic CO
(ii) If the unit uses CEMS to quantify CO
(A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this section, to determine V
(B) If any fossil fuel was combusted during the year, follow the procedures in paragraph (e)(2)(iii) of this section, to determine V
(C) Subtract V
(D) Determine the annual volume of biogenic CO
(E) Calculate the biogenic percentage of the total annual CO
(F) Calculate the annual biogenic CO
(4) For biogas combustion, the Tier 2 or Tier 3 Calculation Methodology shall be used to determine the annual biogenic CO
The CO
(a) For units using the calculation methodologies described in this paragraph, the records required under § 98.3(g) shall include both the company records and a detailed explanation of how company records are used to estimate the following:
(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies described in § 98.33(a) are used.
(2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology in § 98.33(a)(3) is used.
(3) Fossil fuel consumption, when, pursuant to § 98.33(e), the owner or operator of a unit that uses CEMS to quantify CO
(4) Sorbent usage, if the methodology in § 98.33(d) is used to calculate CO
(b) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage and sorbent usage (as applicable) in paragraph (a) of this section, including, but not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(c) For the Tier 2 Calculation Methodology, the applicable fuel sampling and analysis methods incorporated by reference in § 98.7 shall be used to determine the high heat values. For coal, the samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel bunkered or consumed. The minimum frequency of the sampling and analysis for each type of fuel (only for the weeks or months when that fuel is combusted in the unit) is as follows:
(1) Monthly, for natural gas, biogas, fuel oil, and other liquid fuels.
(2) For coal and other solid fuels, weekly sampling is required to obtain composite samples, which are analyzed monthly.
(d) For the Tier 3 Calculation Methodology:
(1) All oil and gas flow meters (except for gas billing meters) shall be calibrated prior to the first year for which GHG emissions are reported under this part, using an applicable flow meter test method listed in § 98.7 or the calibration procedures specified by the flow meter manufacturer. Fuel flow meters shall be recalibrated either annually or at the minimum frequency specified by the manufacturer.
(2) Oil tank drop measurements (if applicable) shall be performed according to one of the methods listed in § 98.7.
(3) The carbon content of the fuels listed in paragraphs (c)(1) and (2) of this section shall be determined monthly. For other gaseous fuels (e.g., refinery gas, or process gas), daily sampling and analysis is required to determine the carbon content and molecular weight of the fuel. An applicable method listed in § 98.7 shall be used to determine the carbon content and (if applicable) molecular weight of the fuel.
(e) For the Tier 4 Calculation Methodology, the CO
(1) For initial certification, use the following procedures:
(i) Section 75.20(c)(2) and (4) and appendix A to part 75) of this chapter.
(ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Specification 3 in appendix B to part 60 (for the CO
(iii) The provisions of an applicable State continuous monitoring program.
(2) If an O
(3) For ongoing quality assurance, follow the applicable procedures in appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program. If appendix F to
(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required by appendix F to part 60 of this chapter need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance.
(f) When municipal solid waste (MSW) is combusted in a unit, the biogenic portion of the CO
Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For all units subject to the requirements of the Acid Rain Program, the applicable missing data substitution procedures in part 75 of this chapter shall be followed for CO
(b) For all units that are not subject to the requirements of the Acid Rain Program, when the Tier 1, Tier 2, Tier 3, or Tier 4 calculation is used, perform missing data substitution as follows for each parameter:
(1) For each missing value of the heat content, carbon content, or molecular weight of the fuel, and for each missing value of CO
(2) For missing records of stack gas flow rate, fuel usage, and sorbent usage, the substitute data value shall be the best available estimate of the flow rate, fuel usage, or sorbent consumption, based on all available process data (e.g., steam production, electrical load, and operating hours). The owner or operator shall document and keep records of the procedures used for all such estimates.
(a) In addition to the facility-level information required under § 98.3, the annual GHG emissions report shall contain the unit-level or process-level emissions data in paragraph (b) and (c) of this section (as applicable) and the emissions verification data in paragraph (d) of this section.
(b)
(1) The unit ID number (if applicable).
(2) A code representing the type of unit.
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr (boilers, combustion turbines, engines, and process heaters only).
(4) Each type of fuel combusted in the unit during the report year.
(5) The calculated CO
(6) The method used to calculate the CO
(7) If applicable, indicate which one of the monitoring and reporting methodologies in part 75 of this chapter was used to quantify the CO
(8) The calculated CO
(9) The total GHG emissions from the unit for the reporting year, i.e., the sum of the CO
(c)
(1)
(i) Group ID number, beginning with the prefix “GP”.
(ii) The ID number of each unit in the group.
(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr).
(iv) Each type of fuel combusted in the units during the reporting year.
(v) The calculated CO
(vi) The methodology used to calculate the CO
(vii) The calculated CO
(viii) The total GHG emissions from the group for the year, i.e., the sum of the CO
(2)
(i) Common stack ID number, beginning with the prefix “CS”.
(ii) ID numbers of the units sharing the common stack.
(iii) Maximum rated heat input capacity of each unit sharing the common stack (mmBtu/hr).
(iv) Each type of fuel combusted in the units during the year.
(v) The methodology used to calculate the CO
(vi) The total CO
(vii) The combined annual CH
(A) If the monitoring is done according to part 75 of this chapter, use Equation C–8 of this subpart, where the term “(HI)
(B) For the Tier 4 calculation methodology, use Equation C–9, C–10a or C–10b of this subpart separately for each type of fuel combusted in the units during the year, and then sum the emissions for all fuel types.
(viii) The total GHG emissions for the year from the units that share the common stack, i.e., the sum of the CO
(3)
(i) Common pipe ID number, beginning with the prefix “CP”.
(ii) ID numbers of the units served by the common pipe.
(iii) Maximum rated heat input capacity of each unit served by the common pipe (mmBtu/hr).
(iv) The type of fuel combusted in the units during the reporting year.
(v) The methodology used to calculate the CO
(vi) The total CO
(vii) The combined annual CH
(viii) The total GHG emissions for the reporting year from the units served by the common pipe, i.e., the sum of the CO
(d)
(1) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, or Tier 4 Calculation Methodology in § 98.33(a)(4) to quantify CO
(i) For the Tier 1 Calculation Methodology, report the total quantity of each type of fuel combusted during the reporting year, in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.
(ii) For the Tier 2 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted during each month (except for MSW). Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The number of required high heat value determinations for each type of fuel for the reporting year (i.e., “n” in Equation C–2a of this subpart, corresponding (as applicable) to the number of operating days or months when each type of fuel was combusted, in accordance with § § 98.33(a)(2) and 98.34(c).
(C) For each month, the high heat value used in Equation C–2a of this subpart for each type of fuel combusted, in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels.
(D) For each reported HHV, indicate whether it is an actual measured value or a substitute data value.
(E) Each method from § 98.7 used to determine the HHV for each type of fuel combusted.
(F) For MSW, the total quantity (i.e., lb) of steam produced from MSW combustion during the year, and “B”, the ratio of the unit's maximum rate heat input capacity to its design rated steam output capacity, in mmBtu per lb of steam.
(iii) For the Tier 3 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted during each month or day (as applicable), in metric tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The number of required carbon content determinations for each type of fuel for the reporting year, corresponding (as applicable) to the number of operating days or months when each type of fuel was combusted, in accordance with §§ 98.33(a)(3) and 98.34(d).
(C) For each operating month or day, the carbon content (CC) value used in Equation C–3, C–4, or C–5 of this subpart (as applicable), expressed as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels.
(D) For gaseous fuel combustion, the molecular weight of the fuel used in Equation C–5 of this subpart, for each operating month or day, in kg per kg-mole.
(E) For each reported CC value, indicate whether it is an actual measured value or a substitute data value.
(F) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the fuel flow meters used to measure the amount of fuel combusted.
(G) For fuel oil combustion, each method from § 98.7 used to make tank drop measurements (if applicable).
(H) Each method from § 98.7 used to determine the CC for each type of fuel combusted.
(I) Each method from § 98.7 used to calibrate the fuel flow meters (if applicable).
(iv) For the Tier 4 Calculation Methodology, report:
(A) The total number of source operating days and the total number of source operating hours in the reporting year.
(B) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program have been selected.
(C) The CO
(D) For CO
(E) The dates and results of the initial certification tests of the CEMS, and
(F) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).
(v) If CO
(A) The total amount of sorbent used during the report year, in metric tons.
(B) The molecular weight of the sorbent.
(C) The ratio (“R”) in Equation C–11 of this subpart.
(vi) When ASTM methods D7459–08 and D6866–06a are used to determine the biogenic portion of the annual CO
(A) The results of each quarterly sample analysis, expressed as a decimal fraction, e.g., if the biogenic fraction of the CO
(B) The total quantity of MSW combusted during the reporting year, in short tons if the Tier 2 Calculation Methodology is used or in metric tons if the Tier 3 calculation methodology is used.
(vii) For units that combust both fossil fuel and biogenic fuel, when CEMS are used to quantify the annual CO
(A) The annual volume of CO
(B) The annual volume of CO
(C) The annual volume of CO
(D) The carbon-based F-factor used in Equation C–14 of this subpart, for each type of fossil fuel combusted, in scf CO
(E) The annual average GCV value used in Equation C–14 of this subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.
(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.
(G) The total annual biogenic CO
(2) Within 7 days of receipt of a written request (e.g., a request by electronic mail) from the Administrator or from the applicable State or local air pollution control agency, the owner or operator shall submit the explanations described in § 98.34(a) and (b), as follows:
(i) A detailed explanation of how company records are used to quantify fuel consumption, if Calculation Methodology Tier 1 or Tier 2 of this subpart is used to calculate CO
(ii) A detailed explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology in § 98.33(a)(3) is used to calculate CO
(iii) A detailed explanation of how sorbent usage is quantified, if the methodology in § 98.33(d) is used to calculate CO
(iv) A detailed explanation of how company records are used to quantify fossil fuel consumption, when, as described in § 98.33(e), the owner or operator of a unit that combusts both fossil fuel and biogenic fuel uses CEMS to quantify CO
The recordkeeping requirements of § 98.3(g) and, if applicable, § 98.34(a) and (b) shall be fully met for affected facilities with stationary combustion sources. Also, the records required under § 98.35(a)(1), documenting the data substitution procedures for missing stack flow rate, fuel flow rate, fuel usage and (if applicable) sorbent usage information and site-specific source testing (as allowed in § 98.33(c)(4)), shall be retained. No special recordkeeping beyond that specified in §§ 98.3, 98.35(a)(4), and 98.34(a) and (b) is required. All required records must be retained for a period of five years.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The electricity generation source category comprises all facilities with one or more electricity generating units, including electricity generating units that are subject to the requirements of the Acid Rain Program.
(b) This source category does not include portable equipment or generating units designated as emergency generators in a permit issued by a State or local air pollution control agency.
You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of either § 98.2(a)(1) or (2).
The annual mass emissions of CO
(a) For each electricity generating unit subject to the requirements of the Acid Rain Program, the owner or operator shall continue to monitor and report CO
(1) The owner or operator shall convert the cumulative annual CO
(2) The annual CH
(b) For each unit that is not subject to the reporting requirements of the Acid Rain Program, the annual CO
(a) For electricity generation units subject to the requirements of the Acid Rain Program, the CO
(b) For electricity generating units that are not subject to the requirements of the Acid Rain Program, the quality assurance and quality control procedures specified in § 98.34 for stationary fuel combustion units shall be followed.
(a) For electricity generation units subject to the requirements of the Acid Rain Program, the applicable missing data substitution procedures in part 75 of this chapter shall be followed for CO
(b) For each electricity generating unit that is not subject to the requirements of the Acid Rain Program, the missing data substitution procedures specified in § 98.35 for stationary fuel combustion units shall be implemented.
(a) For electricity generation units subject to the requirements of the Acid Rain Program, the owner or operator of a facility containing one or more electricity generating units shall meet the data reporting requirements specified in § 98.36(b) and, if applicable, § 98.36(c)(2) or (3).
(b) For electricity generating units not subject to the requirements of the Acid Rain Program, the owner or operator of a facility containing one or more electricity generating units shall meet the data reporting and verification requirements specified in § 98.36.
The owner or operator of a facility containing one or more electricity generating units shall meet the recordkeeping requirements of § 98.3(g) and, if applicable, § 98.37.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid.
You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report N
(b) You must report CO
You must determine annual N
(a) You must conduct an annual performance test to measure N
(b) You must conduct the emissions test using the methods specified in § 98.54(b).
(c) You must measure the adipic acid production rate for the facility during the test and calculate the production rate for the test period in metric tons per hour.
(d) You must calculate an average facility-specific emission factor according to Equation E–1 of this section:
(e) You must calculate annual adipic acid production process emissions of N
(a) You must conduct a new performance test and calculate a new facility-specific emissions factor at least annually. You must also conduct a new performance test whenever the production rate is changed by more than 10 percent from the production rate measured during the most recent performance test. The new emissions factor may be calculated using all available performance test data (i.e., average with the data from previous years), except in cases where process modifications have occurred or operating conditions have changed. Only the data consistent with the reporting period after the changes were implemented shall be used.
(b) You must conduct each emissions test using EPA Method 320 in 40 CFR part 63, Appendix A or ASTM D6348–03 (incorporated by reference—see § 98.7) to measure the N
(c) Each facility must conduct all required performance tests according to a test plan and EPA Method 320 in 40 CFR part 63, appendix A or ASTM D6348–03 (incorporated by reference-see § 98.7). All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (c)(1) through (3) of this section:
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor.
(3) The production rate during the test and how it was determined. The production rate can be determined through sales records, or through direct measurement using flow meters or weigh scales.
Procedures for estimating missing data are not provided for N
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (h) of this section for each adipic acid production facility:
(a) Annual N
(b) Annual adipic acid production capacity (in metric tons).
(c) Annual adipic acid production, in units of metric tons of adipic acid produced.
(d) Number of facility operating hours in calendar year.
(e) Emission rate factor used (lb N
(f) Abatement technology used (if applicable).
(g) Abatement technology efficiency (percent destruction).
(h) Abatement utilization factor (percent of time that abatement system is operating).
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (f) of this section at the facility level:
(a) Annual N
(b) Annual adipic acid production capacity, in metric tons.
(c) Annual adipic acid production, in units of metric tons of adipic acid produced.
(d) Number of facility operating hours in calendar year.
(e) Measurements, records and calculations used to determine the annual production rate.
(f) Emission rate factor used and supporting test or calculation information including the annual emission rate factor determination report specified in § 98.54(c). This report must be available upon request.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A primary aluminum production facility manufactures primary aluminum using the Hall-Héroult manufacturing process. The primary aluminum manufacturing process comprises the following operations:
(1) Electrolysis in prebake and Søderberg cells.
(2) Anode baking for prebake cells.
(b) This source category does not include experimental cells or research and development process units.
You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) Total perfluoromethane (CF
(b) Total CO
(c) Total CO
(d) For CO
(a) Use Equation F–1 of this section to estimate CF
(b) Use the following procedures to calculate CO
(1) For Prebake cells: You must calculate CO
(2) For Søderberg cells you must calculate CO
(2) Use Equation F–6 of this section to calculate emissions from bake furnace packing material.
(a) The smelter-specific slope coefficient must be measured at least every 36 months in accordance with the EPA/IAI Protocol for Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from Primary Aluminum Production (2008).
(b) The minimum frequency of the measurement and analysis is annually except as follows: Monthly—anode effect minutes per cell day, production.
(c) Sources may use smelter-specific values from annual measurements of parameters needed to complete the equations in § 98.63 (e.g., sulfur, ash, and hydrogen contents), or may use default values from Volume III, Section 4.4, in Chapter 4, of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(a) Where anode or paste consumption data are missing, CO
(b) For other parameters, use the average of the two most recent data points.
In addition to the information required by § 98.3(c), you must report the following information at the facility level:
(a) Annual aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on an annual basis:
(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all Søderberg electolysis cells combined.
(2) Anode effect minutes per cell-day, anode effect frequency (AE/cell-day), anode effect duration (minutes).
(3) Smelter-specific slope coefficient and the last date when the smelter-specific-slope coefficient was measured.
(d) Method used to measure the frequency and duration of anode effects.
(e) The following CO
(1) Total anode consumption.
(2) Total CO
(f) The following CO
(1) Total paste consumption.
(2) Total CO
(g) Smelter-specific inputs to the CO
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg).
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Monthly aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on a monthly basis:
(1) Perfluoromethane and perfluoroethane emissions from anode effects in each prebake and Søderberg electolysis cells.
(2) Anode effect minutes per cell-day, anode effect frequency (AE/cell-day), anode effect duration (minutes) from each prebake and Søderberg electolysis cells.
(3) Smelter-specific slope coefficient and the last date when the smelter-specific-slope coefficient was measured.
(d) Method used to measure the frequency and duration of anode effects.
(e) The following CO
(1) Total anode consumption.
(2) Total CO
(f) The following CO
(1) Total paste consumption.
(2) Total CO
(g) Smelter-specific inputs to the CO
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this section.
(a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon.
(b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid raw material.
You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either §
You must report:
(a) Carbon dioxide (CO
(b) CO
(c) For CO
You must determine CO
(a) Any ammonia manufacturing process unit that meets the conditions specififed in § 98.33(b)(5)(iii)(A), (B), and (C), or § 98.33(b)(5)(ii)(A) through (F) shall calculate total CO
(b) If the facility does not measure total emissions with a CEMS, you must calculate the annual CO
(1)
(2)
(3)
(a) Facilities must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.
(b) You must collect a sample of each feedstock on a monthly basis and analyze the carbon content using any suitable method incorporated by reference in § 98.7.
(c) All fuel flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(d) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) and (b) of this section.
(a) For missing feedstock supply rates, use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure.
(b) There are no missing data procedures for carbon content. A re-test must be performed if the data from any monthly measurements are determined to be invalid.
In addition to the information required by § 98.3(c) of subpart A of this part, each annual report must contain the information specified in paragraphs (a) through (c) for each ammonia manufacturing process unit:
(a) Annual CO
(b) Total quantity of feedstock consumed for ammonia manufacturing.
(c) Monthly analyses of carbon content for each feedstock used in ammonia manufacturing (kg carbon/kg of feedstock).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.
(a) Method used for determining quantity of feedstock used.
(b) Monthly analyses of carbon content for each feedstock used in ammonia manufacturing.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn hazardous waste.
You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
Carbon dioxide (CO
CO
(a) Cement kilns that meet the conditions specified in § 98.33(b)(5)(ii) or (iii) shall calculate total CO
(b) If CEMS are not used to determine the total annual CO
(1) Calculate CO
(i) EF
(ii) A default factor of 1.0, which assumes that 100 percent of all carbonates in CKD are calcined, may be used instead of testing to determine EF
(iii) The weight percents of CaO, MgO, non-carbonate CaO, and non-carbonate MgO of clinker used in Equation H–3 must be determined using the measurement methods specified in § 98.84(b).
(3)
(a) You must determine the plant-specific fraction of calcined material in cement kiln dust (CKD) not recycled to the kiln (EFCKD) using an x-ray fluorescence test or other enhanced testing method. The monitoring must be conducted quarterly for each kiln from a CKD sample drawn from bulk CKD storage.
(b) You must determine the weight percents of CaO, MgO, non-carbonate CaO, and non-carbonate MgO in clinker from each kiln using an x-ray fluorescence test or other enhanced testing method. The monitoring must be conducted monthly for each kiln from a clinker sample drawn from bulk clinker storage.
(c) The total organic carbon contents of raw materials must be determined annually using ASTM Method C114–07 or a similar ASTM method approved for total organic carbon determination in raw mineral materials. The analysis must be conducted on sample material drawn from bulk raw material storage for each category of raw material (i.e. limestone, sand, shale, iron oxide, and alumina).
(d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.
(e) The quantity of CKD discarded quarterly by each kiln must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.
(f) The quantity of each category of raw materials consumed annually by the facility (i.e. limestone, sand, shale, iron oxide, and alumina) must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.
If the CEMS approach is used to determine CO
In addition to the information required by § 98.3(b) of this part, each annual report must contain the information specified in paragraphs (a) through (k) of this section for each portland cement manufacturing facility.
(a) The total combined CO
(b) Annual clinker production (tons).
(c) Number of kilns.
(d) Annual CKD production (in metric tons).
(e) Total annual fraction of CKD recycled to the kilns (as a percentage).
(f) Annual weighted average carbonate composition (by carbonate).
(g) Annual weighted average fraction of calcination achieved (for each carbonate, percent).
(h) Site-specific emission factor (metric tons CO
(i) Organic carbon content of the raw material (percent).
(j) Annual consumption of raw material (metric tons).
(k) Facilities that use CEMS must also comply with the data reporting requirements specified in § 98.36(d)(iv).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (i) of this section for each portland cement manufacturing facility.
(a) Monthly carbonate consumption.
(b) Monthly clinker production (tons).
(c) Monthly CKD production (in metric tons).
(d) Total annual fraction of CKD recycled to the kiln (as a percentage).
(e) Monthly analysis of carbonate composition in clinker (by carbonate).
(f) Monthly analysis of fraction of calcination achieved for CKD and each carbonate.
(g) Monthly cement production.
(h) Documentation of calculated site-specific clinker emission factor.
(i) Facilities that use CEMS must also comply with the recordkeeping requirements specified in § 98.37.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The electronics source category consists of any of the processes listed in paragraphs (a)(1) through (5) of this section. Electronics manufacturing facilities include but are not limited to facilities that manufacture semiconductors, liquid crystal displays (LCD), microelectromechanical systems (MEMs), and photovoltaic (PV) cells.
(1) Each electronics manufacturing production process in which the etching process uses plasma-generated fluorine atoms, which chemically react with exposed thin films (e.g., dielectric, metals) and silicon to selectively remove portions of material.
(2) Each electronics manufacturing production process in which chambers used for depositing thin films are cleaned periodically using plasma-generated fluorine atoms from fluorinated and other gases.
(3) Each electronics manufacturing production process in which some fluorinated compounds can be transformed in the plasma processes into different fluorinated compounds which are then exhausted, unless abated, into the atmosphere.
(4) Each electronics manufacturing production process in which the chemical vapor deposition process uses nitrous oxide.
(5) Each electronics manufacturing production process in which fluorinated GHGs are used as heat transfer fluids (HTFs) to cool process equipment, control temperature during device testing, and solder semiconductor devices to circuit boards.
You must report GHG emissions under this subpart if your facility contains an electronics manufacturing process and the facility meets the requirements of either §
(a) You shall report emissions of nitrous oxide and fluorinated GHGs (as defined in § 98.6). The fluorinated GHGs that are emitted from electronics production processes include but are not limited to those listed in Table I–1 of this subpart. You must report:
(1) Fluorinated GHGs from plasma etching.
(2) Fluorinated GHGs from chamber cleaning.
(3) Nitrous oxide from chemical vapor deposition.
(4) Fluorinated GHGs from heat transfer fluid use.
(b) You shall report CO
(a) You shall calculate annual facility-level F–GHG emissions of each F–GHG from all etching processes using Equations I–1 and I–2 of this section:
(b) You shall calculate annual facility-level F–GHG emissions of each F–GHG from all CVD chamber cleaning processes using Equations I–3 and I–4 of this section:
(c) You shall calculate annual facility-level F–GHG emissions for each etching process and each chamber cleaning process using Equations I–5 and I–6 of this section.
(1) Semiconductor facilities that have an annual capacity of greater than 10,500 m
(2) All other electronics facilities shall use the default emission factors for process utilization and by-production formation shown in Tables I–2, I–3, and I–4 of subpart I for semiconductor and MEMs, LCD, and PV manufacturing, respectively.
(d) You shall report annual N
(e) For facilities that use heat transfer fluids, you shall report the annual emissions of fluorinated GHG heat transfer fluids using Equation I–8 of this section.
(a) You must estimate gas consumption according to the requirements in paragraph (a)(1) or (a)(2) of this section for each process or process type, as appropriate.
(1) Monitor changes in container mass and inventories for each gas using weigh scales with an accuracy and precision of one percent of full scale or better. Calculate the gas consumption using Equation I–9 of this section.
(2) Monitor the mass flow of the pure gas into the system using flowmeters. The flowmeters must have an accuracy and precision of one percent of full scale or better.
(b) If you use fluorinated GHG utilization rates and by-product emission factors other than the defaults in Tables I–2, I–3, or I–4 of Subpart I, you must use fluorinated GHG utilization rates and by-product emission factors that have been measured using the International SEMATECH Manufacturing Initiative's Guideline for Environmental Characterization of Semiconductor Process Equipment. You may use fluorinated GHG utilization rates and by-product emission factors measured by manufacturing equipment suppliers if the conditions in paragraph (b)(1) and (2) of this section are met.
(1) The manufacturing equipment supplier has measured the GHG utilization rates and by-product emission factors using the International SEMATECH Guideline.
(2) The conditions under which the measurements were made are representative of your facility's F–GHG emitting processes.
(c) If your facility employs abatement devices and you wish to reflect the emission reductions due to these devices in § 98.93(c), you must verify the destruction or removal efficiency (DRE) of the devices using the methods in either paragraph (c)(1) or (2) of this section.
(1) Experimentally determine the effective dilution through the abatement device and measure abatement DRE during actual or simulated process conditions by following the procedures of this paragraph.
(i) Measure the concentrations of F–GHGs exiting the process tool and entering and exiting the abatement system under operating process and abatement system conditions that are representative of those for which F–GHG emissions are estimated and abatement-system DRE is used for the F–GHG reporting period.
(ii) Measure the dilution through the abatement system and calculate the dilution factor under the representative operating conditions given in paragraph (c)(i) of this section by using the tracer method. This method consists of injecting known flows of a non-reactive gas (such as krypton) at the inlet of the abatement system, measuring the time-averaged concentrations of krypton entering ([Kr]
(iii) Measure the F–GHG concentrations in and out of the device with all process chambers connected to the F–GHG abatement system and under the production and abatement system conditions for which F–GHG emissions are estimated for the reporting period.
(iv) Calculate abatement system DRE using Equation I–11 of this section, where it is assumed that the measurement pressure and temperature at the inlet and outlet of the abatement system are identical and where the relative precision (ε) of the quantity c
(v) The DF may not be obtained by calculation from flows other than those obtained by using the tracer method described in paragraph (ii) of this section.
(2) Install abatement devices that have been tested by a third party (e.g., UL) according to EPA's Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing. This testing may be obtained by the manufacturer of the equipment.
(d) Abatement devices must be operated within the manufacturer's specified equipment lifetime and gas flow and mix limits and must be maintained according to the manufacturer's guidelines.
(e) You shall adhere to the QA/QC procedures of this paragraph when estimating F–GHG and N
(1) You shall follow the QA/QC procedures in the International SEMATECH Manufacturing Initiative's Guideline for Environmental Characterization of Semiconductor Process Equipment when estimating facility-specific gas process utilization and by-product gas formation.
(2) You shall follow the QA/QC procedures in the EPA DRE measurement protocol when estimating abatement device DRE.
(3) You shall certify that abatement devices are maintained in accordance with manufacturer specified guidelines.
(4) You shall certify that gas consumption is tracked to a high degree of precision as part of normal facility operations and that further QA/QC is not required.
(f) You shall adhere to the QA/QC procedures of this paragraph when estimating F–GHG emissions from heat transfer fluid use:
(1) You shall review all inputs to Equation I–4 of this section to ensure that all inputs and outputs to the facility's system are accounted for.
(2) You shall not enter negative inputs into the mass balance Equation I–4 of this section and shall ensure that no negative emissions are calculated.
(3) You shall ensure that the beginning of year inventory matches the end of year inventory from previous year.
(g) All flowmeters, scales, load cells, and volumetric and density measures used to measure quantities that are to be reported under § 98.92 and § 98.96 shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(h) All instruments (e.g., mass spectrometers and fourier transform infrared measuring systems) used to determine the concentration of fluorinated greenhouse gases in process streams shall be calibrated just prior to DRE, gas utilization, or product formation measurement through analysis of certified standards with known concentrations of the same chemicals in the same ranges (fractions by mass) as the process samples. Calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Test Method 205, 40 CFR Part 51, Appendix M may also be used.
(a) For semiconductor facilities that have an annual capacity of greater than 10,500 m
(b) For facilities using heat transfer fluids and missing data for one or more of the parameters in Equation I–8, you shall estimate heat transfer fluid emissions using the arithmetic average of the emission rates for the year immediately preceding the period of missing data and the months immediately following the period of missing data. Alternatively, you may estimate missing information using records from the heat transfer fluid supplier. You shall document the method used and values estimated for all missing data values.
(c) If the methods specified in paragraphs (a) and (b) of this section are likely to significantly under- or overestimate the value of the parameter during the period when data were missing (e.g., because the monitoring failure was linked to a process disturbance that is likely to have significantly increased the F–GHG emission rate), you shall develop a best estimate of the parameter, documenting the methods used, the rationale behind them, and the reasons why the methods specified in paragraphs (a) and (b) of this section would lead to a significant under-or overestimate of the parameter.
In addition to the information required by § 98.3(c), you shall include in each annual report the following information for each electronics manufacturer.
(a) Emissions of each GHG emitted from all plasma etching processes, all chamber cleaning, all chemical vapor deposition processes, and all heat transfer fluid use, respectively.
(b) The method, mass of input F–GHG gases, and emission factors used for estimating F–GHG emissions.
(c) Production in terms of substrate surface area (e.g., silicon, PV-cell, LCD).
(d) Factors used for gas process utilization and by-product formation, and the source and uncertainty for each factor.
(e) The verified DRE and its uncertainty for each abatement device used, if you have verified the DRE pursuant to § 98.94(c).
(f) Fraction of each gas fed into each process type with abatement devices.
(g) Description of abatement devices, including the number of devices of each manufacturer and model.
(h) For heat transfer fluid emissions, inputs in the mass-balance Equation.
(i) Example calculations for F–GHG, N
(j) Estimate of the overall uncertainty in the emissions estimate.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Data used to estimate emissions including all spreadsheets and copies of calculations used to estimate emissions.
(b) Documentation for the values used for GHG utilization rates and by-product emission factors, including documentation that these were measured using the the International SEMATECH Manufacturing Initiative's Guideline for Environmental Characterization of Semiconductor Process Equipment.
(c) The date and results of the initial and any subsequent tests of emission control device DRE, including the following information:
(1) Dated certification, by the technician who made the measurement, that the dilution factor was determined using the tracer method.
(2) Dated certification, by the technician who made the measurement, that the DRE was calculated using the formula given in § 98.94(c)(1)(iv).
(3) Documentation of the measured flows, concentrations and calculations used to calculate DF, relative precision (ε), and DRE.
(d) The date and results of the initial and any subsequent tests to determine process tool gas utilization and by-product formation factors.
(e) Abatement device calibration and maintenance records.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
An ethanol production facility is a facility that produces ethanol from the fermentation of sugar, starch, grain, or cellulosic biomass feedstocks; or produces ethanol synthetically from ethylene or hydrogen and carbon monoxide.
You must report GHG emissions under this subpart if your facility contains an ethanol production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) Emissions of CO
(b) Emissions of CH
(c) Emissions of CH
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The ferroalloy production source category consists of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.
You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report the CO
(b) You must report the CH
(c) You must report the CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) For each EAF at your facility used for ferroalloy production, you must determine the mass of carbon in each carbon-containing input and output material for the electric arc furnace for each calendar month using Equation K–1 of this section. Carbon containing input materials include carbon eletrodes and carbonaceous reducing agents.
(2) You must determine the total CO
(c) For the electric arc furnaces used at your facility for the production of any ferroalloy listed in Table K–1 of this subpart, you must determine the total CH
(1) For each EAF, calculate annual CH
(2) You must determine the total CH
If you determine CO
(a) Determine the mass of each solid carbon-containing process input and output material by direct measurements or calculations using process operating information, and record the total mass
(b) For each process input and output material identified in paragraph (a) of this section, you must determine the average carbon content of the material for the specified period using information provided by your material supplier or by collecting and analyzing a representative sample of the material.
(c) For each input material identified in paragraph (a) of this section for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed by an independent certified laboratory at least annually using the test methods (and their QA/QC procedures) in § 98.7. Use ASTM E1941–04 (“Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”) for analysis of metal ore and alloy product; ASTM D5373–02 (“Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”) for analysis of carbonaceous reducing agents and carbon electrodes, and ASTM C25–06 (“Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”) for analysis of flux materials such as limestone or dolomite.
For the carbon input procedure in § 98.113(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input or output material consumption, the substitute data value shall be the best available estimate of the mass of the input or output material. The owner or operator shall document and keep records of the procedures used for all such estimates.
(c) If you are required to calculate CH
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (f) of this section.
(a) Annual CO
(b) Annual CH
(c) Facility ferroalloy product production capacity (metric tons).
(d) Annual facility production quantity for each ferroalloy product (metric tons).
(d) Number of facility operating hours in calendar year.
(f) If you use the carbon balance procedure, report for each carbon-containing input and output material consumed or used (other than fuel), the information specified in paragraphs (g)(1) and (2) of this section.
(1) Annual material quantity (in metric tons).
(2) Annual average of the monthly carbon content determinations for each material and the method used for the determination (e.g., supplier provided information, analyses of representative samples you collected).
In addition to the records required by § 98.3(g) of this part, you must retain the records specified in paragraphs (a) through (e) of this section.
(a) Monthly facility production quantity for each ferroalloy product (in metric tons).
(b) Number of facility operating hours each month.
(c) If you use the carbon balance procedure, record for each carbon-containing input and output material consumed or used (other than fuel), the information specified in paragraphs (c)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the determination.
(d) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input input and output to each electric arc furnace. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(e) If you are required to calculate CH
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The fluorinated gas production source category consists of facilities that produce a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG or the generation of HFC–23 during the production of HCFC–22.
You must report GHG emissions under this subpart if your facility contains a fluorinated greenhouse gas production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report the CO
(b) You must report the total mass of each fluorinated GHG emitted from each fluorinated GHG production process and from all fluorinated GHG production processes at the facility.
(a) The total mass of each fluorinated GHG product emitted annually from all fluorinated GHG production processes shall be estimated by using Equation L–1 of this section:
(b) The total mass of fluorinated GHG by-product k emitted annually from all fluorinated GHG production processes shall be estimated by using Equation L–2 of this section:
(c) The total mass of each fluorinated GHG product emitted from production process i over the period p shall be estimated at least daily by calculating the difference between the expected production of the fluorinated GHG based on the consumption of reactants (e.g., HF and a chlorocarbon reactant) and the measured production of the fluorinated GHG, accounting for yield losses related to by-products and wastes. This calculation shall be performed for each reactant, using Equation L–3 of this section. Estimated emissions shall equal the average of the results obtained for each reactant.
(d) The total mass of the reactant that is consumed by production process i over the period p shall be estimated by using Equation L–4 of this section:
(e) The mass of wastes removed from production process i in stream j and destroyed over the period p shall be estimated using Equation L–5 of this section:
(f) Yield loss related to by-product k for production process i over period p shall be estimated using Equation L–6 of this section:
(g) If by-product k is responsible for yield loss in production process i and occurs in any process stream in more than trace concentrations, the mass of by-product k generated by production process i over the period p shall be estimated using Equation L–7 of this section:
(h) If by-product k is responsible for yield loss, is a fluorinated GHG, occurs in any process stream in more than trace concentrations, and is not completely recaptured or completely destroyed; the total mass of by-product k emitted from production process i over the period p shall be estimated at least daily using Equation L–8 of this section:
(a) The total mass of fluorinated GHGs produced over the period p shall be estimated at least daily using the methods and measurements set forth in §§ 98.413(b) and 98.414.
(b) The total mass of each reactant fed into the production process shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better.
(c) The total mass of each reactant permanently removed from the production process shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the reactant, the concentration of the reactant shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the reactant permanently removed from the production process.
(d) If the waste permanently removed from the production process and fed into the destruction device contains more than trace concentrations of the fluorinated GHG product, the mass of waste fed into the destruction device shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the product, the concentration of the product shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples.
(e) If a by-product is responsible for yield loss and occurs in any process stream in more than trace concentrations, the mass flow of each process stream that contains more than trace concentrations of the by-product shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the by-product, the concentration of the by-product shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples.
(f) If a by-product is a fluorinated GHG, occurs in more than trace concentrations in any process stream, occurs in more than trace concentrations in any stream that is recaptured or is fed into a destruction device, and is not completely recaptured or completely destroyed; the mass flow of each stream that contains more than trace concentrations of the by-product and that is recaptured or is fed into the destruction device or shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the by-product, the concentration of the by-product shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples.
(g) All flowmeters, scales, load cells, and volumetric and density measures used to measure quantities that are to be reported under § 98.126 shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(h) All gas chromatographs used to determine the concentration of fluorinated greenhouse gases in process streams shall be calibrated at least monthly through analysis of certified standards with known concentrations of the same chemicals in the same ranges (fractions by mass) as the process samples. Calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Test Method 205, 40 CFR Part 51, Appendix M may also be used.
(i) For purposes of equation L–5, the destruction efficiency can initially be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device. Fluorinated GHG production facilities that destroy fluorinated GHGs shall conduct annual measurements of mass flow and fluorinated GHG concentrations at the outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6. Tests shall be conducted under conditions that are typical for the production process and destruction device at the facility. The sensitivity of the emissions tests shall be sufficient to detect emissions equal to 0.01 percent of the mass of fluorinated GHGs being fed into the destruction device. If the test indicates that the actual DE of the destruction device is lower than the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for the previously determined DE in the calculations in § 98.123, or
(2) Perform more extensive performance testing of the DE of the oxidizer and use the DE determined by the more extensive testing in the calculations in § 98.123.
(j) In their estimates of the mass of fluorinated GHGs destroyed, fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(k) Fluorinated GHG production facilities shall account for fluorinated GHG emissions that occur as a result of startups, shutdowns, and malfunctions, either recording fluorinated GHG emissions during these events, or documenting that these events do not result in significant fluorinated GHG emissions.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(1) For each missing value of the mass of fluorinated GHG produced, the mass of reactants fed into the production process, the mass of reactants permanently removed from the production process, the mass flow of process streams containing more than trace concentrations of by-products that lead to yield losses, or the mass of wastes fed into the destruction device; the substitute value of that parameter shall be a secondary mass measurement taken during the period the primary mass measurement was not available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable; then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product.
(2) For each missing value of fluorinated GHG concentration, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(3) If the methods specified in paragraphs (a)(1) and (2) of this section are likely to significantly under- or overestimate the value of the parameter during the period when data were missing, you shall develop a best estimate of the parameter, documenting the methods used, the rationale behind them, and the reasons why the methods specified in (a)(1) and (2) would lead to a significant under- or overestimate of the parameter.
(a) In addition to the information required by § 98.3(c), you shall report the following information for each production process at the facility.
(1) The total mass of the fluorinated GHG produced in metric tons, by chemical.
(2) The total mass of each reactant fed into the production process in metric tons, by chemical.
(3) The total mass of each reactant permanently removed from the production process in metric tons, by chemical.
(4) The total mass of the fluorinated GHG product removed from the production process and destroyed.
(5) The mass of each by-product generated.
(6) The mass of each by-product destroyed at the facility.
(7) The mass of each by-product recaptured and sent off-site for destruction.
(8) The mass of each by-product recaptured for other purposes.
(9) The mass of each fluorinated GHG emitted.
(b) Where missing data have been estimated pursuant to § 98.125, you shall report the information specified in paragraphs (b)(1) and (2) of this section.
(1) The reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(2) Where the missing data have been estimated pursuant to § 98.125(a)(3), you shall also report the rationale for the methods used to estimate the missing data and why the methods specified in § 98.125 (a)(1) and (2) would lead to a significant under- or overestimate of the parameter(s).
(c) A fluorinated GHG production facility that destroys fluorinated GHGs shall report the results of the annual fluorinated GHG concentration measurements at the outlet of the destruction device, including:
(1) Flow rate of fluorinated GHG being fed into the destruction device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at the outlet of the destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate calculated from paragraphs(c)(2) and (c)(3) of this section in kg/hr.
(d) A fluorinated GHG production facility that destroys fluorinated GHGs shall submit a one-time report containing the following information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(a) In addition to the data required by §§ 98.123 and 98.126, you shall retain the following records:
(1) Dated records of the data used to estimate the data reported under §§ 98.123 and 98.126.
(2) Dated records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.124(g) and (h).
(b) In addition to the data required by paragraph (a) of this section, the designated representative of a fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report and annaul destruction device outlet reports in § 98.126(c) and (d).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Food processing facilities prepare raw ingredients for consumption by animals or humans. Food processing facilities transform raw ingredients into food, transform food into other forms for consumption by humans or animals, or transform food for further processing by the food processing industry.
You must report GHG emissions under this subpart if your facility contains a food processing operation and the facility meets the requirements of either
You must report:
(a) Emissions of CO
(b) Emissions of CH
(c) Emissions of CH
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass.
(b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart.
You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CO
(b) You must report the CO
(a) If you operate and maintain a continuous emission monitoring system (CEMS) that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the carbonate-based mineral mass fraction.
(2) Determine the quantity of each carbonate-based raw material charged to the furnace.
(3) Apply the appropriate emission factor for each carbonate-based raw material charged to the furnace, as shown in Table N–1 to this subpart.
(4) Use Equation N–1 of this subpart to calculate process mass emissions of CO
(5) You must determine the total process CO
(c) As an alternative to data provided by the raw material supplier, a value of 1.0 can be used for the mass fraction (MF
(a) You shall determine annual amounts of carbonate-based raw materials charged to each continuous glass melting furnace using calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year.
(b) If raw material supplier data are used to determine carbonate-based mineral mass fractions according to § 98.143(b)(1), measurements of the mass fraction of each carbonate-based mineral in the carbonate-based raw materials shall be made at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis conducted by a certified laboratory using a suitable method published by a consensus standards organization (
(a) Missing data on the monthly amounts of carbonate-based raw materials charged to any continuous glass melting furnace shall be replaced by the average of the data from the previous month and the following month for each carbonate-based raw material charged.
(b) Missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials shall be replaced using the assumption that the mass fraction of each carbonate based mineral is 1.0.
You shall report the information specified in paragraphs (a) through (d) of this section for each continuous glass melting furnace.
(a) Annual process emissions of CO
(b) Annual quantity of each carbonate-based raw material charged, in metric tons/yr.
(c) Annual quantity of glass produced, in metric tons/yr.
(d) If process CO
In addition to the information required by § 98.3(g), you must retain the records listed in paragraphs (a) through (e) of this section.
(a) Total number of continuous glass melting furnaces.
(b) Monthly glass production rate for each continuous glass melting furnace.
(c) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace.
(d) If process CO
(1) Data on carbonate-based mineral mass fractions provided by the raw material supplier.
(2) Results of all tests used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace.
(e) All other documentation used to support the reported GHG emissions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The HCFC–22 production and HFC–23 destruction source category consists of HCFC–22 production processes and HFC–23 destruction processes.
(a) An HCFC–22 production process produces HCFC–22 (chlorodifluoromethane, or CHClF
(b) An HFC–23 destruction process is any process in which HFC–23 undergoes destruction. An HFC–23 destruction process may or may not be co-located with an HCFC–22 production process at the same facility.
You must report GHG emissions under this subpart if your facility contains a HCFC–22 production or HFC–23 destruction process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report the CO
(b) You must report HFC–23 emissions from HCFC–22 production processes and HFC–23 destruction processes.
(a) The total mass of HFC–23 generated from each HCFC–22 production process shall be estimated by using one of two methods, as applicable:
(1) Where the mass flow of the combined stream of HFC–23 and another reaction product (
(2) Where the mass of only a reaction product other than HFC–23 (either HCFC–22 or HCl) is measured, multiply the ratio of the daily (or more frequent) measurement of the HFC–23 concentration and the daily (or more frequent) measurement of the other product concentration by the daily (or more frequent) mass produced of the other product. To estimate annual HFC–23 production, sum the daily (or more frequent) estimates of the quantities of HFC–23 produced over the year. This calculation is summarized in Equation O–2 of this section, assuming that the other product is HCFC–22. If the other product is HCl, HCl may be substituted for HCFC–22 in Equations O–2 and O–3 of this section.
(b) The mass of HCFC–22 produced over the period p shall be estimated by using Equation O–3 of this section:
(c) For HCFC–22 production facilities that do not use a thermal oxidizer or have a thermal oxidizer that is not directly connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–4 of this section:
(d) For HCFC–22 production facilities that use a thermal oxidizer connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–5 of this section:
(e) The mass of HFC–23 emitted annually from equipment leaks (for use in Equation O–5 of this section) shall be estimated by using Equation O–6 of this section:
(f) The mass of HFC–23 emitted annually from process vents (for use in Equation O–5 of this section) shall be estimated by using Equation O–7 of this section:
(g) For facilities that destroy HFC–23, the total mass of HFC–23 destroyed shall be estimated by using Equation O–8 of this section:
(h) The total mass of HFC–23 emitted from destruction devices shall be estimated by using Equation O–9 of this section:
These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to § 98.153.
(a) The concentrations (fractions by weight) of HFC–23 and HCFC–22 in the product stream shall be measured at least daily using equipment and methods (
(b) The mass flow of the product stream containing the HFC–23 shall be measured continuously using a flow meter with an accuracy and precision of 1.0 percent of full scale or better.
(c) The mass of HCFC–22 or HCl coming out of the production process shall be measured at least daily using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(d) The mass of any used HCFC–22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured at least daily (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(e) The loss factor LF in Equation O–3 of this subpart for the mass of HCFC–22 produced shall have the value 1.015 or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of HCFC–22 between the reactor and the point of measurement at the facility where production is being estimated.
(f) The mass of HFC–23 packaged for sale shall be measured at least daily (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(g) The mass of HFC–23 sent off-site for destruction shall be measured at least daily (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC–23, the concentration of the fluorinated GHG shall be measured at least daily using equipment and methods (
(h) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA Method 21 at 40 CFR part 60, appendix A–7, and defining a leak as follows:
(1) A leak source that could emit HFC–23, and
(2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured.
(i) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC–23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (h) of this section.
(j) The mass of HFC–23 emitted from process vents shall be estimated at least monthly by conducting emissions tests at process vents at least annually and by incorporating the results of the most recent emissions test into Equation O–6 of this subpart. Emissions tests shall be conducted in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall be sufficient to detect an emission rate that would result in annual emissions of 200 kg of HFC–23 if sustained over one year.
(k) For purposes of Equation O–8, the destruction efficiency can initially be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device. HFC–23 destruction facilities shall conduct annual measurements of mass flow and HFC–23 concentrations at the outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6. Tests shall be conducted under conditions that are typical for the production process and destruction device at the facility. The sensitivity of the emissions tests shall be sufficient to detect emissions equal to 0.01 percent of the mass of HFC–23 being fed into the destruction device. If the test indicates that the actual DE of the destruction device is lower than the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for the previously determined DE in the calculations in § 98.153.
(2) Perform more extensive performance testing of the DE of the oxidizer and use the DE determined by the more extensive testing in the calculations in § 98.153.
(l) Designated representatives of HCFC–22 production facilities shall account for HFC–23 generation and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC–23 generation and emissions during these events, or documenting that these events do not result in significant HFC–23 generation and/or emissions.
(m) The mass of HFC–23 fed into the destruction device shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC–23, the concentrations of the HFC–23 shall be measured at least daily using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC–23 destroyed.
(n) In their estimates of the mass of HFC–23 destroyed, designated representatives of HFC–23 destruction facilities shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(o) All flowmeters, scales, and load cells used to measure quantities that are to be reported under § 98.156 shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(p) All gas chromatographs used to determine the concentration of HFC–23 in process streams shall be calibrated at least monthly through analysis of certified standards (or of calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Test Method 205, 40 CFR part 51, appendix M) with known HFC–23 concentrations that are in the same range (fractions by mass) as the process samples.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process
(1) For each missing value of the HFC–23 or HCFC–22 concentration, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product measurement. If that measurement is taken significantly downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses.
(3) Notwithstanding paragraphs (a)(1) and (2) of this section, if the owner or operator has reason to believe that the methods specified in paragraphs (a)(1) and (2) of this section are likely to significantly under- or overestimate the value of the parameter during the period when data were missing (e.g., because the monitoring failure was linked to a process disturbance that is likely to have significantly increased the HFC–23 generation rate), the designated representative of the HCFC–22 production facility shall develop his or her best estimate of the parameter, documenting the methods used, the rationale behind them, and the reasons why the methods specified in (a)(1) and (2) would probably lead to a significant under- or overestimate of the parameter.
(a) In addition to the information required by § 98.3(c), the designated representative of an HCFC–22 production facility shall report the following information at the facility level:
(1) The mass of HCFC–22 produced in metric tons.
(2) The mass of reactants fed into the process in metric tons of reactant.
(3) The mass (in metric tons) of materials other than HCFC–22 and HFC–23 (i.e., unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and that are permanently removed from the process.
(4) The method for tracking startups, shutdowns, and malfunctions and HFC–23 generation/emissions during these events.
(5) The names and addresses of facilities to which any HFC–23 was sent for destruction, and the quantities of HFC–23 (metric tons) sent to each.
(6) The total mass of the HFC–23 generated in metric tons.
(7) The mass of any HFC–23 packaged for sale in metric tons.
(8) The mass of any HFC–23 sent off site for destruction in metric tons.
(9) The mass of HFC–23 emitted in metric tons.
(10) The mass of HFC–23 emitted from equipment leaks in metric tons.
(11) The mass of HFC–23 emitted from process vents in metric tons.
(b) Where missing data have been estimated pursuant to § 98.155, the designated representative of the HCFC–22 production facility or HCF–23 destruction facility shall report the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(1) Where the missing data have been estimated pursuant to § 98.155(a)(3), the designated representative shall also report the rationale for the methods used to estimate the missing data and why the methods specified in § 98.155(a)(1) and (2) would probably lead to a significant under- or overestimate of the parameter(s).
(c) In addition to the information required by § 98.3(c), the designated representative of a facility that destroys HFC–23 shall report the following for each HFC–23 destruction process:
(1) The mass of HFC–23 fed into the thermal oxidizer.
(2) The mass of HFC–23 destroyed.
(3) The mass of HFC–23 emitted from the thermal oxidizer.
(d) The designated representative of each HFC–23 destruction facility shall report the results of the facility's annual HFC–23 concentration measurements at the outlet of the destruction device, including:
(1) The flow rate of HFC–23 being fed into the destruction device in kg/hr.
(2) The concentration (mass fraction) of HFC–23 at the outlet of the destruction device.
(3) The flow rate at the outlet of the destruction device in kg/hr.
(4) The emission rate calculated from paragraphs (c)(2) and (3) of this section in kg/hr.
(e) The designated representative of an HFC–23 destruction facility shall submit a one-time report including the following information:
(1) The destruction unit's destruction efficiency (DE).
(2) The methods used to determine the unit's destruction efficiency.
(3) The methods used to record the mass of HFC–23 destroyed.
(4) The name of other relevant federal or state regulations that may apply to the destruction process.
(5) If any changes are made that affect HFC–23 destruction efficiency or the methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change.
(a) In addition to the data required by § 98.3(g), the designated representative of an HCFC–22 production facility shall retain the following records:
(1) The data used to estimate HFC–23 emissions.
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to § 98.154(o) and (p).
(b) In addition to the data required by § 98.3(g), the designated representative of a HFC–23 destruction facility shall retain the following records:
(1) Records documenting their one-time and annual reports in § 98.156(c), (d), and (e).
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.154(o) and (p).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A hydrogen production source category produces hydrogen gas that is consumed at sites other than where it is produced.
(b) This source category comprises process units that produce hydrogen by oxidation, reaction, or other transformations of feedstocks.
(c) This source category includes hydrogen production facilities located within a petroleum refinery and that are not owned or under the direct control of the refinery owner and operator.
You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) CO
(b) CO
(c) For CO
You must determine CO
(a)
(b)
(1)
(2)
CO
(3)
(a) Facilities that use CEMS must comply with the monitoring and QA/QC procedures specified in § 98.34(e).
(b) The quantity of gaseous or liquid feedstock consumed must be measured continuously using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.
(c) You must collect a sample of each feedstock and analyze the carbon content of each sample using appropriate test methods incorporated by reference in § 98.7. The minimum frequency of the fuel sampling and analysis is monthly.
(d) All fuel flow meters, gas composition monitors, and heating value monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow
(e) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(a) For missing feedstock supply rates, use the lesser of the maximum supply rate that the unit is capable of processing or the maximum supply rate that the meter can measure.
(b) There are no missing data procedures for carbon content. A re-test must be performed if the data from any monthly measurements are determined to be invalid.
(c) For missing CEMS data, you must use the missing data procedures in § 98.35.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each process unit:
(a) Facilities that use CEMS must comply with the procedures specified in § 98.36(a)(1)(iv).
(b) Annual total consumption of feedstock for hydrogen production; annual total of hydrogen produced; and annual total of ammonia produced, if applicable.
(c) Monthly analyses of carbon content for each feedstock used in hydrogen production (kg carbon/kg of feedstock).
In addition to the information required by § 98.3(g), you must retain the following records:
(a) For all CEMS, you must comply with the CEMS recordkeeping requirements in § 98.37.
(b) Monthly analyses of carbon content for each feedstock used in hydrogen production.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The iron and steel production source category includes facilities with any of the following processes: Taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrated iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility.
You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report combustion-related CO
(b) You must report process-related CO
(c) You must report CO
(a) For each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, argon-oxygen decarburization vessel, and direct reduction furnace, you must determine CO
(1) Continuous emissions monitoring system (CEMS). If you operate and maintain a CEMS that measures CO
(2)
(i) For taconite indurating furnaces, estimate CO
(ii) For basic oxygen process furnaces, estimate CO
(iii) For non-recovery coke oven batteries, estimate CO
(iv) For sinter processes, estimate CO
(v) For EAFs, estimate CO
(vi) For argon-oxygen decarburization vessels, estimate CO
(vii) For direct reduction furnaces, estimate CO
(3)
(i) You must measure the production rate or feed rate, as applicable, during the test and calculate the average rate for the test period in metric tons per hour.
(ii) You must calculate the hourly CO
(iii) You must calculate a site-specific emission factor for the process in metric tons of CO
(iv) You must calculate CO
(b) You must determine emissions of CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you determine CO
(1) For each process input and output other than fuels, determine the mass rate of each process input and output and record the totals for each process input and output for each calendar month. Determine the mass rate of fuels using the procedures for combustion units in § 98.34.
(2) For each process input and output other than fuels, sample each process input and output weekly and prepare a monthly composite sample for carbon analysis. For each process input that is a fuel, determine the carbon content using the procedures for combustion units in § 98.34.
(3) For each process input and output other than fuels, the carbon content must be analyzed by an independent certified laboratory using test method ASTM C25–06 (“Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”).
(3) For each process input and output other than fuels, the carbon content must be analyzed by an independent certified laboratory using the test methods specified in this paragraph.
(A) Use ASTM C25–06 (“Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”) for:
(i) Limestone, dolomite, and slag; ASTM D5373–08 (“Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”) for coal, coke, and other carbonaceous materials; ASTM E1915–07a (“Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry”) for iron ore, taconite pellets, and other iron-bearing materials.
(ii) ASTM E1019–03 (“Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and Cobalt Alloys”) for iron and ferrous scrap.
(iii) ASTM E1019–03 (“Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and Cobalt Alloys”), ASTM CS–104 (“Carbon Steel of Medium Carbon Content”), ISO/TR 15349–1:1998 (“Unalloyed steel—Determination of low carbon content. Part 1”), or ISO/TR 15349–3: 1998 (“Unalloyed steel—Determination of low carbon content. Part 3”) as applicable for steel.
(c) If you determine CO
(1) Conduct an annual performance test under normal process operating conditions and at a production rate no less than 90 percent of the process rated capacity.
(2) For the furnace exhaust from basic oxygen furnaces, EAFs, argon-oxygen decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least nine complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.
(3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 9 hours.
(4) Conduct the stack test using EPA Method 3A in 40 CFR part 60, Appendix A–2 to measure the CO
(5) Conduct a new performance test and calculate a new site-specific emission factor if your fuel type or fuel/feedstock mix changes, the process changes in a manner that affects energy efficiency by more than 10 percent, or the process feed materials change in a manner that changes the carbon content of the fuel or feed by more than 10 percent.
(6) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must contain all information and data used to derive the emission factor.
(d) For CH
(e) For a coke pushing process, determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density.
There are no allowances for missing data for facilities that estimate emissions using the carbon balance procedure in § 98.173(a)(2) or the site-emission factor procedure in § 98.133(a)(3); 100 percent data availability is required.
In addition to the information required by § 98.3(c), each annual report must contain the information required in paragraphs (a) through (g) of this section for coke pushing and for each taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; sinter process; EAF; argon-oxygen decarburization vessel; and direct reduction furnace, as applicable:
(a) Annual CO
(b) Annual total for all process inputs and outputs when the carbon balance is used for specific processes by calendar quarters (short tons).
(c) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel by calendar quarters.
(d) Production capacity (in tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel.
(e) Annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast furnaces, direct reduced iron furnaces, and electric arc furnaces.
(f) Site-specific emission factor for all process units for which the site-specific emission factor approach is used.
(g) Facilities that use CEMS must also comply with the data reporting requirements specified in § 98.36(d)(iv).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (f) of this section, as applicable.
(a) Annual CO
(b) Monthly total for all process inputs and outputs for each calendar quarter when the carbon balance is used for specific processes.
(c) Monthly analyses of carbon content for each calendar quarter when the carbon balance is used for specific processes.
(d) Site-specific emission factor for all process units for which the site-specific emission factor approach is used.
(e) Annual production quantity for taconite pellets, coke, sinter, iron, and raw steel with records for each calendar quarter.
(f) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques. A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to, lead-acid batteries) are recycled by smelting into elemental lead or lead alloys.
You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report the CO
(b) You must report the CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) For each smelting furnace at your facility used for lead production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnaces used at your facility for lead production for each calendar month and estimate total CO
(2) You must determine the total CO
If you determine CO
(a) Determine the mass of each solid carbon-containing input material by direct measurement of the quantity of the material placed in the unit or by calculations using process operating information, and record the total mass for the material for each calendar month.
(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material for each calendar month using information provided by your material supplier or by collecting and analyzing a representative sample of the material.
(c) For each input material identified in paragraph (a) of this section for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed by an independent certified laboratory each calendar month using the test methods and their QA/QC procedures in § 98.7. Use ASTM E1941–04 (“Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”) for analysis of lead bearing ore, lead scrap, and lead ingot; ASTM D5373–02 (“Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”) for analysis of carbonaceous reducing agents, and ASTM C25–06 (“Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”) for analysis of flux materials such as limestone or dolomite.
For the carbon input procedure in § 98.183(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input material consumption, the substitute data value shall be the best available estimate of the mass of the input material. The owner or operator shall document and keep records of the procedures used for all such estimates.
In addition to the information required by § 98.3(c) of this part, each annual report must contain the information specified in paragraphs (a) through (e) of this section.
(a) Total annual CO
(b) Facility lead product production capacity (metric tons).
(c) Annual facility production quantity (metric tons).
(d) Number of facility operating hours in calendar year.
(e) If you use the carbon input procedure, report for each carbon-containing input material consumed or used (other than fuel), the following information:
(1) Annual material quantity (in metric tons).
(2) Annual weighted average carbon content determined for material and the method used for the determination (e.g., supplier provided information, analyses of representative samples you collected).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section.
(a) Monthly facility production quantity for each lead product (in metric tons).
(b) Number of facility operating hours each month.
(c) If you use the carbon input procedure, record for each carbon-containing input material consumed or used (other than fuel), the information specified in paragraphs (c)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the determination.
(d) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Lime manufacturing processes use a rotary lime kiln to produce a lime product (e.g., calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other products) from limestone or dolomite by means of calcination. The lime manufacturing source category consists of marketed lime manufacturing facilities and non-marketed lime manufacturing facilities.
You must report GHG emissions under this subpart if your facility contains a lime manufacturing process and the facility meets the requirements of either §
(a) You must report CO
(b) You must report CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) You must calculate a monthly emission factor for each kiln for each type of lime produced using Equation S–1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each kiln:
(2) You must calculate the correction factor for by-product/waste products at the kiln (monthly) using Equation S–2 of this section:
(3) You must calculate annual CO
(4) You must determine the total CO
(a) Determine the quantity of each type of lime produced at each kiln and the quantity of each type of calcined by-product/waste produced for each lime type, such as LKD, at the kiln on a monthly basis. The quantity of each type of calcined by-product/waste produced at the kiln must include material that is sold or used in a product, inventoried, or disposed of. The quantity of lime types and LKD produced monthly by each kiln must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.
(b) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime and each type of calcined by-product/waste produced from each lime type by an off-site laboratory analysis on a monthly basis. This determination must be performed according to the requirements of ASTM C25–06, “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime” (incorporated by reference—see § 98.7) and the procedures in “CO
(c) You must use the most recent analysis of calcium oxide and magnesium oxide content of each lime product in monthly calculations.
(d) You must follow the quality assurance/quality control procedures (including documentation) in the National Lime Association's “CO
For the procedure in § 98.193(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations.
(a) For each missing value of quantity of lime types, CaO and MgO content, and quantity of LKD the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing records of mass of raw material consumption, the substitute data value shall be the best available estimate of the mass of inputs. The owner or operator shall document and keep records of the procedures used for all such estimates.
(a) In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a)(1) through (5) of this section for each lime kiln:
(1) Annual CO
(2) Annual lime production (in metric tons);
(3) Annual lime production capacity (in metric tons) per facility;
(4) All monthly emission factors, and;
(5) Number of operating hours in calendar year.
(b) Facilities that use CEMS must also comply with the data reporting requirements specified in § 98.36.
(a) In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a)(1) through (4) of this section for each lime kiln:
(1) Annual calcined by-products/waste products (by lime type summed from monthly data.
(2) Lime production (by lime type) per month (metric tons).
(3) Calculation of emission factors.
(4) Results of chemical composition analysis (by lime product) per month.
(5) Monthly correction factors for by-products/waste products for each kiln.
(b) Facilities that use CEMS must also comply with the recordkeeping requirements specified in § 98.37.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The magnesium production and processing source category consists of the following facilities:
(a) Any site where magnesium metal is produced through smelting (including electrolytic smelting), refining, or remelting operations.
(b) Any site where molten magnesium is used in alloying, casting, drawing, extruding, forming, or rolling operations.
You must report GHG emissions under this subpart if your facility contains a magnesium production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report emissions of the following gases in kilograms and metric tons CO
(1) Sulfur hexafluoride (SF
(2) HFC–134a.
(3) The fluorinated ketone, FK 5–1–12.
(4) Any other fluorinated GHGs.
(5) Carbon dioxide (CO
(b) You must report CO
(a) Calculate CO
(b) To estimate consumption of cover gases or carrier gases by monitoring changes in container masses and inventories, consumption of each cover gas or carrier gas shall be estimated using Equation T–2 of this section:
(c) To estimate consumption of cover gases or carrier gases by monitoring changes in the masses of individual containers as their contents are used, consumption of each cover gas or carrier gas shall be estimated using Equation T–3 of this section:
(d) For purposes of Equation T–3 of this section, the mass of the cover gas used over the period p shall be estimated by using Equation T–4 of this section:
(a) Consumption of cover gases and carrier gases may be estimated by monitoring the changes in container weights and inventories using Equation T–2 of this subpart, by monitoring the changes in individual container weights as the contents of each container are used using Equations T–3 and T–4 of this subpart, or by monitoring the mass flow of the pure cover gas or carrier gas into the cover gas distribution system. Consumption must be estimated at least annually.
(b) When estimating consumption by monitoring the mass flow of the pure cover gas or carrier gas into the cover gas distribution system, you must use gas flow meters with an accuracy of one percent of full scale or better.
(c) When estimating consumption using Equation T–2 of this subpart, you must ensure that all the quantities required by Equation T–2 of this subpart have been measured using scales or load cells with an accuracy of one percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier (e.g., for the contents of containers containing new gas or for the heels remaining in containers returned to the gas supplier); however, you remain responsible for the accuracy of these masses and weights under this subpart.
(d) When estimating consumption using Equations T–3 and T–4 of this subpart, you must monitor and record container identities and masses as follows:
(1) Track the identities and masses of containers leaving and entering storage with check-out and check-in sheets and procedures. The masses of cylinders returning to storage shall be measured immediately before the cylinders are put back into storage.
(2) Ensure that all the quantities required by Equations T–3 and T–4 of this subpart have been measured using scales or load cells with an accuracy of one percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier (e.g., for the contents of cylinders containing new gas or for the heels remaining in cylinders returned to the gas supplier); however, you remain responsible for the accuracy of these masses or weights under this subpart.
(e) All flowmeters, scales, and load cells used to measure quantities that are to be reported under this subpart shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures specified by the flowmeter, scale, or load cell manufacturer may be used. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(a) A complete record of all measured parameters used in the GHG emission calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter will be used in the calculations as specified in paragraph (b) of this section.
(b) Replace missing data on the consumption of cover gases by multiplying magnesium production during the missing data period by the average cover gas usage rate from the most recent period when operating conditions were similar to those for the period for which the data are missing. Calculate the usage rate for each cover gas using Equation T–5 of this section:
In addition to the information required by § 98.3(c), each annual report must include the following information for the magnesium production and processing facility:
(a) Total GHG emissions for your facility by gas in metric tons and CO
(b) Type of production process (e.g. primary, secondary, die casting).
(c) Magnesium production amount in metric tons for each process type.
(d) Cover gas flow rate and composition.
(e) Amount of CO
(f) For any missing data, you must report the length of time the data were missing, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
(g) The facility's cover gas usage rate.
(h) If applicable, an explanation of any change greater than 30 percent in the facility's cover gas usage rate (e.g., installation of new melt protection technology or leak discovered in the cover gas delivery system that resulted in increased consumption).
(i) A description of any new melt protection technologies adopted to account for reduced GHG emissions in any given year.
In addition to the records specified in § 98.3(g), you must retain the following information for the magnesium production or processing facility:
(a) Check-out and weigh-in sheets and procedures for cylinders.
(b) Accuracy certifications and calibration records for scales.
(c) Residual gas amounts in cylinders sent back to suppliers.
(d) Invoices for gas purchases and sales.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category consists of any equipment that uses limestone, dolomite, ankerite, magnesite, silerite, rhodochrosite, sodium carbonate, or any other carbonate in a manufacturing process.
(b) This source category does not include carbonates consumed for producing cement, glass, ferroalloys, iron and steel, lead, lime, pulp and paper, or zinc.
You must report GHG emissions from miscellaneous uses of carbonate if your facility meets the requirements of either § 98.2(a)(1) or (2).
You must report CO
Calculate process emissions of CO
As an alternative to measuring the calcination fraction (F
(a) The total mass of carbonate consumed can be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders, or purchase records.
(b) Determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis conducted by a certified laboratory using a suitable method such as using an x-ray fluorescence test or other enhanced testing method published by a consensus standards organization (e.g., ASTM, ASME, API, etc.).
There are no missing data procedures for miscellaneous uses of carbonates. A complete record of all measured parameters used in the GHG emissions calculations is required. A re-test must be performed if the data from any measurements are determined to be invalid.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (d) of this section at the facility level.
(a) Annual CO
(b) Annual carbonate consumption (by carbonate type in tons).
(c) Annual fraction calcinations.
(d) Average annual mass fraction of carbonate-based mineral in carbonate-based raw material by carbonate type.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section.
(a) Records of monthly carbonate consumption (by carbonate type). You must also document the procedures used to ensure the accuracy of monthly carbonate consumption.
(b) Annual chemical analysis of mass fraction of carbonate-based mineral in carbonate-based raw material by carbonate type.
(c) Records of all carbonate purchases and deliveries.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
A nitric acid production facility uses oxidation, condensation, and absorption to produce a weak nitric acid (30 to 70 percent in strength).
You must report GHG emissions under this subpart if your facility contains a nitric acid production
(a) You must report N
(b) You must report CO
You must determine annual N
(a) You must conduct an annual performance test to measure N
(b) You must conduct the emissions test(s) using either EPA Method 320 in 40 CFR part 63, appendix A or ASTM D6348–03 incorporated by reference in § 98.7 to measure the N
(c) You must measure the production rate during the test(s) and calculate the production rate for the test period in tons (100 percent acid basis) per hour.
(d) You must calculate a site-specific emission factor for each nitric acid production line according to Equation V–1 of this section:
(e) You must calculate N
(a) You must conduct a new performance test and calculate a new site-specific emissions factor at least annually. You must also conduct a new performance test whenever the production rate of a production line is changed by more than 10 percent from the production rate measured during the most recent performance test. The new emissions factor may be calculated using all available performance test data (i.e., averaged with the data from previous years), except in cases where process modifications have occurred or operating conditions have changed. Only the data consistent with the period after the changes were implemented shall be used.
(b) Each facility must conduct the performance test(s) according to a test plan and EPA Method 320 in 40 CFR part 63, Appendix A or ASTM D6348–03 (incorporated by reference—see § 98.7). All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. The report must include the items in paragraphs (b)(1) through (3) of this section.
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor(s).
(3) The production rate during each test and how it was determined. The production rate can be determined through sales records or by direct measurement using flow meters or weigh scales.
Procedures for estimating missing data are not provided for N
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (h) of this section for each nitric acid production line:
(a) Annual nitric acid production capacity (metric tons).
(b) Annual nitric acid production (metric tons).
(c) Number of operating hours in the calendar year (hours).
(d) Emission factor(s) used (lb N
(e) Type of nitric acid process used.
(f) Abatement technology used (if applicable).
(g) Abatement utilization factor (percent of time that abatement system is operating).
(h) Abatement technology efficiency.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a)
(a) Records of significant changes to process.
(b) Annual test reports of N
(c) Calculations of the site-specific emissions factor(s).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This source category consists of the following facilities:
(a) Offshore petroleum and natural gas production facilities.
(b) Onshore natural gas processing facilities.
(c) Onshore natural gas transmission compression facilities.
(d) Underground natural gas storage facilities.
(e) Liquefied natural gas storage facilities.
(f) Liquefied natural gas import and export facilities.
You must report GHG emissions from oil and natural gas systems if your facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CO
(1) Acid gas removal (AGR) vent stacks.
(2) Blowdown vent stacks.
(3) Centrifugal compressor dry seals.
(4) Centrifugal compressor wet seals.
(5) Compressor fugitive emissions.
(6) Compressor wet seal degassing vents.
(7) Dehydrator vent stacks.
(8) Flare stacks.
(9) Liquefied natural gas import and export facilities fugitive emissions.
(10) Liquefied natural gas storage facilities fugitive emissions.
(11) Natural gas driven pneumatic pumps.
(12) Natural gas driven pneumatic manual valve actuator devices.
(13) Natural gas driven pneumatic valve bleed devices.
(14) Non-pneumatic pumps.
(15) Offshore platform pipeline fugitive emissions.
(16) Open-ended lines (oels).
(17) Pump seals.
(18) Platform fugitive emissions.
(19) Processing facility fugitive emissions.
(20) Reciprocating compressor rod packing.
(21) Storage station fugitive emissions.
(22) Storage tanks.
(23) Storage wellhead fugitive emissions.
(24) Transmission station fugitive emissions.
(b) You must report the CO
(a) Estimate emissions using either an annual direct measurement, as specified in § 98.234, or an engineering estimation method specified in this section. You may use the engineering estimation method only for sources for which a method is specified in this section.
(b) You may use engineering estimation methods described in this section to calculate emissions from the following fugitive emissions sources:
(1) Acid gas removal vent stacks.
(2) Natural gas driven pneumatic pumps.
(3) Natural gas driven pneumatic manual valve actuator devices.
(4) Natural gas driven pneumatic valve bleed devices.
(5) Blowdown vent stacks.
(6) Dehydrator vent stacks.
(c) A combination of engineering estimation described in this section and direct measurement described in § 98.234 shall be used to calculate emissions from the following fugitive emissions sources:
(1) Flare stacks.
(2) Storage tanks.
(3) Compressor wet seal degassing vents.
(d) You must use the methods described in § 98.234 (d) or (e) to conduct annual leak detection of fugitive emissions from all sources listed in § 98.232(a). If fugitive emissions are detected, engineering estimation methods may be used for sources listed in paragraphs (b) and (c) of this section. If engineering estimation is used, emissions must be calculated using the appropriate method from paragraphs (d)(1) through (9) of this section:
(1) Acid gas removal vent stack. Calculate acid gas removal vent stack fugitive emissions using simulation software packages, such as ASPEN
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate and weight.
(vii) If the acid gas removal unit is capturing CO
(2) Natural gas driven pneumatic pump. Calculate fugitive emissions from a natural gas driven pneumatic pump as follows:
(i) Calculate fugitive emissions using manufacturer data.
(A) Obtain from the manufacturer specific pump model natural gas emission per unit volume of liquid pumped at operating pressures.
(B) Maintain a log of the amount of liquid pumped annually from individual pumps.
(C) Calculate the natural gas fugitive emissions for each pump using Equation W–1 of this section.
(D) Both CH
(ii) If manufacturer data for F
(3) Natural gas driven pneumatic manual valve actuator devices. Calculate fugitive emissions from a natural gas driven pneumatic manual valve actuator device as follows:
(i) Calculate fugitive emissions using manufacturer data.
(A) Obtain from the manufacturer specific pneumatic device model natural gas emission per actuation.
(B) Maintain a log of the number of times the pneumatic device was actuated throughout the reporting period.
(C) Calculate the natural gas fugitive emissions for each manual valve actuator using Equation W–2 of this section.
(D) Calculate both CH
(ii) Follow the method in § 98.234(i)(2) if manufacturer data are not available.
(4) Natural gas driven pneumatic valve bleed devices. Calculate fugitive emissions from a natural gas driven pneumatic valve bleed device as follows:
(i) Calculate fugitive emissions using manufacturer data.
(A) Obtain from the manufacturer specific pneumatic device model natural gas bleed rate during normal operation.
(B) Calculate the natural gas fugitive emissions for each valve bleed device using Equation W–3 of this section.
(C) Calculate both CH
(ii) Follow the method in § 98.234(i)(3) if manufacturer data are not available.
(5) Blowdown vent stacks. Calculate fugitive emissions from blowdown vent stacks as follows:
(i) Calculate the total volume (including, but not limited to pipelines and vessels) between isolation valves (V
(ii) Retain logs of the number of blowdowns for each equipment type.
(iii) Calculate the total annual fugitive emissions using the following Equation W–4 of this section:
(iv) Calculate natural gas volumetric fugitive emissions at standard conditions using calculations in paragraph (e) of this section.
(v) Calculate both CH
(6) Dehydrator vent stacks. Calculate fugitive emissions from a dehydrator vent stack using a simulation software packages, such as GLYCalc
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (natural gas pneumatic/air pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type: Including, but not limited to, triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
(vii) Use of stripping natural gas.
(viii) Use of flash tank separator (and disposition of recovered gas).
(ix) Hours operated.
(x) Wet natural gas temperature, pressure, and composition.
(7) Flare stacks. Calculate fugitive emissions from a flare stack as follows:
(i) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 95 percent for non-steam aspirated flares and 98 percent for steam aspirated or air injected flares.
(ii) Calculate volume of natural gas sent to flare from velocity measurement in § 98.234(j) using manufacturer's manual for the specific meter used to measure velocity.
(iii) Calculate GHG volumetric fugitive emissions at actual conditions using Equation W–5 of this section:
(iv) Calculate GHG volumetric fugitive emissions at standard conditions using Equation W–6 of this section.
(v) Calculate both CH
(8) Storage tanks. Calculate fugitive emissions from a storage tank as follows:
(i) Calculate the total annual hydrocarbon vapor fugitive emissions using Equation W–7 of this section:
(ii) Estimate hydrocarbon vapor volumetric fugitive emissions at standard conditions using calculations in paragraph (e) of this section.
(iii) Estimate CH
(iv) Estimate CH
(9) Compressor wet seal degassing vents. Calculate fugitive emissions from compressor wet seal degassing vents as follows:
(i) Calculate volume of natural gas sent to vent from velocity measurement in § 98.234(j) using manufacturer's manual for the specific meter used to measure velocity.
(ii) Calculate natural gas volumetric fugitive emissions at standard conditions using calculations in paragraph (e) of this section.
(iii) Calculate both CH
(e) Calculate natural gas volumetric fugitive emissions at standard conditions by converting ambient temperature and pressure of natural gas fugitive emissions to standard temperature and pressure natural using Equation W–9 of this section.
(f) Calculate GHG volumetric fugitive emissions at standard conditions as specified in paragraphs (f)(1) and (2) of this section.
(1) Estimate CH
(2) For Equation W–10 of this section, the mole percent, M
(i) GHG mole percent in produced natural gas for offshore petroleum and natural gas production facilities.
(ii) GHG mole percent in feed natural gas for all fugitive emissions sources upstream of the de-methanizer and GHG mole percent in facility specific residue gas to transmission pipeline systems for all fugitive emissions sources downstream of the de-methanizer for onshore natural gas processing facilities.
(iii) GHG mole percent in transmission pipeline natural gas that passes through the facility for onshore natural gas transmission compression facilities.
(iv) GHG mole percent in natural gas stored in underground natural gas storage facilities.
(v) GHG mole percent in natural gas stored in LNG storage facilities.
(vi) GHG mole percent in natural gas stored in LNG import and export facilities.
(g) Calculate GHG mass fugitive emissions at standard conditions by converting the GHG volumetric fugitive emissions into mass fugitive emissions using Equation W–11 of this section.
(a) You must use the methods described in paragraphs (d) or (e) in this section to conduct annual leak detection of fugitive emissions from all sources listed in § 98.232(a), whether in operation or on standby. If fugitive emissions are detected for sources listed in paragraph (b) of this section, you must use the measurement methods described in paragraph(c) of this section to measure emissions from each source with fugitive emissions.
(b) You shall use detection instruments described in paragraphs (d) and (e) of this section to monitor the following fugitive emissions:
(1) Centrifugal compressor dry seals fugitive emissions.
(2) Centrifugal compressor wet seals fugitive emissions.
(3) Compressor fugitive emissions.
(4) LNG import and export facility fugitive emissions.
(5) LNG storage station fugitive emissions.
(6) Non-pneumatic pumps fugitive emissions.
(7) Open-ended lines (OELs) fugitive emissions.
(8) Pump seals fugitive emissions.
(9) Offshore platform pipeline fugitive emissions.
(10) Platform fugitive emissions.
(11) Processing facility fugitive emissions.
(12) Reciprocating compressor rod packing fugitive emissions.
(13) Storage station fugitive emissions.
(14) Transmission station fugitive emissions.
(15) Storage wellhead fugitive emissions.
(c) You shall use a high volume sampler, described in paragraph (f) of this section, to measure fugitive emissions from the sources detected in § 98.234(b), except as provided in paragraphs (c)(1) and (2) of this section:
(1) Where high volume samplers cannot capture all of the fugitive emissions, you shall use calibrated bags described in paragraph (g) of this section or meters described in paragraph (h) of this section to measure the following fugitive emissions:
(i) Open-ended lines (OELs).
(ii) Centrifugal compressor dry seals fugitive emissions.
(iii) Centrifugal compressor wet seals fugitive emissions.
(iv) Compressor fugitive emissions.
(v) Pump seals fugitive emissions.
(vi) Reciprocating compressor rod packing fugitive emissions.
(vii) Flare stacks and storage tanks, except that you shall use meters in
(2) Use hot wire anemometer to calculate fugitive emissions from centrifugal compressor wet seal degassing vents and flares where it is unsafe or too high a flow rate to use calibrated bags.
(d) Infrared Remote Fugitive Emissions Detection.
(1) Use infrared fugitive emissions detection instruments that can identify specific equipment sources as emitting. Such instruments must have the capability to trace a fugitive emission back to the specific point where it escapes the process and enters the atmosphere.
(2) If you are using instruments that visually display an image of fugitive emissions, you shall inspect the emissions source from multiple angles or locations until the entire source has been viewed without visual obstructions at least once annually.
(3) If you are using any other infrared detection instruments, such as those based on infrared laser reflection, you shall monitor all potential emission points at least once annually.
(4) Perform fugitive emissions detection under favorable conditions, including but not limited to during daylight hours, in the absence of precipitation, in the absence of high wind, and, for active laser devices, in front of appropriate reflective backgrounds within the detection range of the instrument.
(5) Use fugitive emissions detection and measurement instrument manuals to determine optimal operating conditions.
(e) Use organic vapor analyzers (OVAs) and toxic vapor analyzers (TVAs) for all fugitive emissions detection that are safely accessible at close-range.
(1) Check each potential emissions source, all joints, connections, and other potential paths to the atmosphere for emissions.
(2) Evaluate the lag time between the instrument sensing and alerting caused by the residence time of a sample in the probe shall be evaluated; upon alert, the instrument shall be slowly retraced over the source to pinpoint the location of fugitive emissions.
(3) Use Method 21 of 40 CFR part 60, appendix A–7, Determination of Volatile Organic Compound Leaks to calibrate OVAs and TVAs.
(f) Use a high volume sampler to measure only cold and steady emissions within the capacity of the instrument.
(1) A trained technician shall conduct measurements. The technician shall be conversant with all operating procedures and measurement methodologies relevant to using a high volume sampler, including, but not limited to, positioning the instrument for complete capture of the fugitive emissions without creating backpressure on the source.
(2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then you shall use anti-static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer's manual.
(3) Estimate CH
(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH
(g) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures and the entire fugitive emissions volume can be captured for measurement.
(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag.
(2) Perform three measurements of the time required to fill the bag; report the emissions as the average of the three readings.
(3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(e).
(4) Estimate CH
(5) Obtain consistent results when measuring the time it takes to fill the bag with fugitive emissions.
(h) Channel all emissions from a single source directly through the meter when using metering (e.g., rotameters, turbine meters, and others).
(1) Use an appropriately sized meter so that the flow does not exceed the full range of the meter in the course of measurement and conversely has sufficient momentum for the meter to register continuously in the course of measurement.
(2) Estimate natural gas volumetric fugitive emissions at standard conditions using calculations in § 98.233(f).
(3) Estimate CH
(4) Calibrate the meter using either one of the two methods provided as follows:
(i) Develop calibration curves by following the manufacturer's instruction.
(ii) Weigh the amount of gas that flows through the meter into or out of a container during the calibration procedure using a master weigh scale (approved by National Institute of Standards and Technology (NIST) or calibrated using standards traceable by NIST). Determine correction factors for the flow meter according to the manufacturer's instructions. Record deviations from the correct reading at several flow rates. Plot the data points, comparing the flowmeter output to the actual flowrate as determined by the master weigh scale and use the difference as a correction factor.
(i) Where engineering estimation as described in § 98.233 is not possible, use direct measurement methods as follows:
(1) If manufacturer data on pneumatic pump natural gas emission are not available, conduct a one-time measurement to determine natural gas emission per unit volume of liquid pumped using a calibrated bag for each pneumatic pump, when it is pumping liquids. Determine the volume of liquid being pumped from the manufacturer's manual to provide the amount of natural gas emitted per unit of liquid pumped.
(i) Record natural gas conditions (temperature and pressure) and convert natural gas emission per unit volume of liquid pumped at actual conditions into natural gas emission per pumping cycle at standard conditions using Equation W–9 of § 98.233.
(ii) Calculate annual fugitive emissions from the pump using Equation W–1, by replacing the manufacturer's data on emission (variable F
(iii) Estimate CH
(2) If manufacturer data on pneumatic manual valve actuator device natural gas emission are not available, conduct a one-time measurement to determine natural gas emission per actuation using a calibrated bag for each pneumatic device per actuation.
(i) Record natural gas conditions (temperature and pressure) and convert natural gas emission at actual conditions into natural gas emission per
(ii) Calculate annual fugitive emissions from the pneumatic device using Equation W–2 of this section, by replacing the manufacturer's data on emission (variable A
(iii) Estimate CH
(3) If manufacturer data on natural gas driven pneumatic valve bleed rate is not available, conduct a one-time measurement to determine natural gas bleed rate using a high volume sampler or calibrated bag or meter for each pneumatic device.
(i) Record natural gas conditions (temperature and pressure) to convert natural gas bleed rate at actual conditions into natural gas bleed rate at standard conditions using Equation W–9 of this subpart.
(ii) Calculate annual fugitive emissions from the pneumatic device using Equation W–3 of this subpart, by replacing the manufacturer's data on bleed rate (variable B) in the equation with the standard conditions bleed rate calculated in § 98.234(i)(3)(i).
(iii) Estimate CH
(j) Parameters for calculating emissions from flare stacks, compressor wet seal degassing vents, and storage tanks.
(1) Estimate fugitive emissions from flare stacks and compressor wet seal degassing vents as follows:
(i) Insert flow velocity measuring device (such as hot wire anemometer or pitot tube) directly upstream of the flare stack or compressor wet seal degassing vent to determine the velocity of gas sent to flare or vent.
(ii) Record actual temperature and pressure conditions of the gas sent to flare or vent.
(iii) Sample representative gas to the flare stack or compressor wet seal degassing vent every quarter to evaluate the composition of GHGs present in the stream. Record the average of the most recent four gas composition analyses, which shall be conducted using ASTM D1945–03 (incorporated by reference, see § 98.7).
(2) Estimate fugitive emissions from storage tanks as follows:
(i) Measure the hydrocarbon vapor emissions from storage tanks using a flow meter described in paragraph (h) of this section for a test period that is representative of the normal operating conditions of the storage tank throughout the year and which includes a complete cycle of accumulation of hydrocarbon liquids and pumping out of hydrocarbon liquids from the storage tank.
(ii) Record the net (related to working loss) and gross (related to flashing loss) input of the storage tank during the test period.
(iii) Record temperature and pressure of hydrocarbon vapors emitted during the test period.
(iv) Collect a sample of hydrocarbon vapors for composition analysis
(k) Component fugitive emissions sources that are not safely accessible within the operator's arm's reach from the ground or stationary platforms are excluded from the requirements of this section.
(1) Determine annual emissions assuming that the fugitive emissions were continuous from the beginning of the reporting period or last recorded zero detection in the current reporting period and continuing until the fugitive emissions is repaired.
There are no missing data procedures for this source category. A complete record of all measured parameters used in the GHG emissions calculations is required. If data are lost or an error occurs during annual emissions measurements, you must repeat the measurement activity for those sources until a valid measurement is obtained.
In addition to the information required by § 98.3(c), each annual report must report emissions data as specified in this section.
(a) Annual emissions reported separately for each of the operations listed in paragraphs (a)(1) through (6) of this section. Within each operation, emissions from each source type must be reported in the aggregate. For example, an underground natural gas storage facility with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number.
(1) Offshore petroleum and natural gas production facilities.
(2) Onshore natural gas processing facilities.
(3) Onshore natural gas transmission compression facilities.
(4) Underground natural gas storage facilities.
(5) Liquefied natural gas storage facilities.
(6) Liquefied natural gas import and export facilities.
(b) Emissions reported separately for standby equipment.
(c) Emissions calculated for these sources shall assume no CO
(d) Activity data for each aggregated source type level for which emissions are being reported.
(e) Engineering estimate of total component count.
(f) Total number of compressors and average operating hours per year for compressors for each operation listed in paragraphs (a)(1) through (6) of this section.
(g) Minimum, maximum and average throughput for each operation listed in paragraphs (a)(1) through (6) of this section.
(h) Specification of the type of any control device used, including flares, for any source type listed in 98.232(a).
(i) For offshore petroleum and natural gas production facilities, the number of connected wells, and whether they are producing oil, gas, or both.
(j) Detection and measurement instruments used.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected, whether quantification was made pursuant to § 98.234(k) and measurements.
(c) Calibration reports for detection and measurement instruments used.
(d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The petrochemical production source category consists of any facility that produces acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol as an intended product, except as specified in paragraph (b) of this section.
(b) An integrated process is part of the petrochemical source category only if the petrochemical is the primary product of the integrated process.
You must report GHG emissions under this subpart if your facility contains a petrochemical production process and the facility meets the requirements of either §
You must report the information in paragraphs (a) through (d) of this section:
(a) CO
(b) CO
(c) CO
(d) CH
(a) Determine process-based GHG emissions in accordance with the procedures specified in either paragraph (a)(1) or (2) of this section, and if applicable, comply with the procedures in paragraph (b) of this section.
(1)
(i) If you operate and maintain a CEMS that measures total CO
(ii) If you elect to install CEMS to comply with this subpart, you must route all process vent emissions to one or more stacks and use a CEMS on each stack (except flare stacks) to measure CO
(2)
(i) Measure the volume of each gaseous and liquid feedstock and product continuously with a flow meter by following the procedures outlined in § 98.244(b)(2). Fuels used for combustion purposes are not considered to be feedstocks.
(ii) Measure the mass rate of each solid feedstock and product by following the procedures outlined in § 98.244(b)(1) and record the total for each calendar week.
(iii) Collect a sample of each feedstock and product at least once per week and determine the carbon content of each sample according to the procedures in § 98.244(b)(3).
(iv) If you determine that the weekly average concentration of a specific compound in a feedstock or product is always greater than 99.5 percent by volume (or mass for liquids and solids), then as an alternative to the sampling and analysis specified in paragraph (a)(2)(iii) of this section, you may calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound during periods of normal operation. You must maintain records of any determination made in accordance with this paragraph along with all supporting data, calculations, and other information. This alternative may not be used for products during periods of operation when off-specification product is produced. You must reevaluate determinations made under this paragraph after any process change that affects the feedstock or product composition. You must keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average weekly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.
(v) Estimate CO
(b) If you have an integrated process unit that is determined to be part of the petrochemical production source category, comply with paragraph (a) of this section by including terms for additional carbon-containing products in Equations X–1 through X–3 of this section as necessary.
(a) Each facility that uses CEMS to estimate emissions from process vents must comply with the procedures specified in § 98.34(e).
(b) Facilities that use the mass balance methodology in § 98.243(a)(2) must comply with paragraphs (b)(1) through (3) of this section.
(1) Measure the mass rate of each solid feedstock and product (e.g., using belt scales or weighing at the loadout points of your process unit) and record the total for each calendar week. You must document procedures used to ensure the accuracy of the measurements of the feedstock and product flows including, but not limited to, calibration of all weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices shall be recorded, and the technical basis for these estimates shall be recorded.
(2) Measure the volume of each gaseous and liquid feedstock and product for each process unit continuously with a flow meter. All feedstock and product flow meters must be calibrated prior to the first reporting year, using any applicable method incorporated by reference in § 98.7(b)(1) through (6), (c)(1), (f)(3)(i) through (ii), or (g)(1). You should use the flow meter accuracy test procedures in appendix D to part 75 of this chapter. Alternatively, calibration procedures specified by the equipment manufacturer may be used. Flow meters and gas composition monitors shall be recalibrated annually or at the frequency specified by another applicable rule or the manufacturer, whichever is more frequent.
(3) Collect a sample of each feedstock and product for each process unit at least once per week and determine the carbon content of each sample using an applicable ASTM method incorporated by reference in § 98.7(a)(15), (23), or (24). Alternatively, you may determine the composition of the sample using a gas chromatograph and then calculate the carbon content based on the composition and molecular weights for compounds in the sample. Determine the composition of gas and liquid samples using either: ASTM D1945–03 incorporated by reference in § 98.7 (a)(8) of subpart A of this part; ASTM D6060–96(2001) incorporated by reference in § 98.7; ASTM D2502–88(2004)e1 incorporated by reference in § 98.7; method UOP539–97 incorporated by reference in § 98.7; or EPA Method 18, 40 CFR part 60, appendix A–6; or Methods 8031, 8021, or 8015 in “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” EPA Publication No. SW–846, Third Edition, September 1986, as amended by Update I, November 15, 1992. Calibrate the gas chromatograph using the procedures in the method prior to each use. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding weekly period. For carbon black products, samples shall be taken of each grade or type of product produced during the weekly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed weekly or a composite of samples collected more frequently and analyzed weekly.
(a) For missing feedstock flow rates, product flow rates, and carbon contents, use the same procedures as for missing flow rates and carbon contents for fuels as specified in § 98.35.
(b) For missing CO
(a) Facilities using the mass balance methodology in § 98.243(a)(2) must report the information specified in paragraphs (a)(1) through (9) of this section for each type of petrochemical produced, reported by process unit.
(1) Identification of the petrochemical process.
(2) Annual CO
(3) Methods used to determine feedstock and product flows and carbon contents.
(4) Number of actual and substitute data points for each measured parameter.
(5) Annual quantity of each feedstock consumed.
(6) Annual quantity of each product and by-product produced, including all products from integrated processes that are part of the petrochemical production source category.
(7) Each carbon content measurement for each feedstock, product, and by-product.
(8) All calculations, measurements, equipment calibrations, certifications, and other information used to assess the uncertainty in emission estimates and the underlying volumetric flow rates, mass flow rates, and carbon contents of feedstocks and products.
(9) Identification of any combustion units that burned process off-gas.
(b) Each facility that uses CEMS to determine emissions from process vents must report the verification data specified in § 98.36(d)(1)(iv).
In addition to the recordkeeping requirements in § 98.3(g), you must retain the following records:
(a) The CEMS recordkeeping requirements in § 98.37, if you operate a CEMS on process vents.
(b) Results of feedstock or product composition determinations conducted in accordance with § 98.243(a)(2)(iv).
(c) Start and end times and calculated carbon contents for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(a)(2)(iv) for determining carbon content of feedstock or product.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A petroleum refinery is any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives.
(b) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; land disposal units; sulfur recovery plants. hydrogen plants (non-merchant plants only).
You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report:
(a) CO
(b) CO
(c) CO
(d) CO
(e) CO
(f) CO
(g) CH
(h) CO
(i) CH
(j) CO
(k) CO
(a) For stationary combustion sources, if you operate and maintain a CEMS that measures total CO
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) and (2) of this section for combustion systems fired with refinery fuel gas.
(1) Calculate the CO2 emissions according to the applicable requirements in paragraphs (b)(1)(i) through (iii) of this section.
(i)
(ii)
(iii)
(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event.
(B) For periods of normal operation, use the average heating value measured for the refinery fuel gas for the heating value of the flare gas.
(C) Calculate the CO2 emissions using Equation Y–1 of this section.
(2) Calculate CH4 and N2O emissions according to the requirements in § 98.33(c)(2) using the emission factors for Refinery Gas in Table C–3 in subpart C of this part.
(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (4) of this section.
(1) For catalytic cracking units and fluid coking units that use a continuous CO
(2) For catalytic cracking units and fluid coking units that do not use a continuous CO
(i) Calculate the CO
(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using Equation Y–3 of this section.
(iii) If a CO boiler or other post-combustion device is used, calculate the GHG emissions from the fuel fired to the CO boiler or post-combustion device using the methods for stationary combustion sources in paragraph (a) of this section and report this separately for the combustion unit.
(3) Calculate CH
(4) Calculate N
(d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part for combustion sources. Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.
(e) For catalytic reforming units, calculate the CO
(1) Calculate CO
(2) Calculate CO
(f) For on-site sulfur recovery plants, calculate CO
(1)
(2)
(3) Calculate the CO
(4) As an alternative to the monitoring methods in paragraphs (f)(1) through (3) of this section, you may use a continuous flow monitor and CO
(g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (3) of this section.
(1) For coke calcining units that use a continuous CO
(2) For coke calcining units that do not use a continuous CO
(i) Calculate the CO
(ii) Calculate the CO
(3) For all coke calcining units, use the CO
(h) For asphalt blowing operations, calculate GHG emissions according to the applicable provisions in paragraphs (h)(1) and (2) of this section.
(1) For uncontrolled asphalt blowing operations, calculate CH
(2) For controlled asphalt blowing operations, calculate CO
(i) For delayed coking units, calculate the CH
(j) For each process vent not covered in paragraphs (a) through (i) of this section, calculate GHG emissions using the Equation Y–12 of this section. You must use Equation Y–12 for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas.
(k) For uncontrolled blowdown systems, you must either use the methods for process vents in paragraph (j) of this section or calculate CH
(l) For equipment leaks, calculate CH
(1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA–453/R–95–017, NTIS PB96–175401).
(2) Use Equation Y–14 of this section.
(m) For storage tanks, calculate CH
(1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH
(2) For storage tanks that process unstabilized crude oil, calculate CH
(n) For crude oil, intermediate, or product loading operations for which the equilibrium vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH
(a) All fuel flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, etc.). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters, gas composition monitors, and heating value monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer.
(b) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(c) All CO
A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For each missing value of the heat content, carbon content, or molecular weight of the fuel, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing oil and gas flow rates, use the standard missing data procedures in section 2.4.2 of appendix D to part 75 of this chapter.
(c) For missing CO
(d) For hydrogen plants, use the missing data procedures in subpart P of this part.
(e) For petrochemical production units, use the missing data procedures in subpart X of this part.
(f) For on-site landfills, use the missing data procedures in subpart HH of this part.
(g) For on-site wastewater treatment systems, use the missing data procedures in subpart II of this part.
In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (e) of this section.
(a) For combustion sources, including flares, use the data reporting requirements in § 98.36.
(b) For hydrogen plants, use the data reporting requirements in subpart P of this part.
(c) For petrochemical production units, use the data reporting requirements in subpart X of this part.
(d) For on-site landfills, use the data reporting requirements in subpart HH of this part.
(e) For on-site wastewater treatment systems, use the data reporting requirements in subpart II of this part.
(f) For catalytic cracking units, traditional fluid coking units, catalytic reforming units, sulfur recovery plants, and coke calcining units, owners and operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, sulfur recovery plant, or coke calcining unit).
(3) Maximum rated throughput of the unit, in bbl/stream day, metric tons sulfur produced/stream day, or metric tons coke calcined/stream day, as applicable.
(4) The calculated CO
(5) A description of the method used to calculate the CO
(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c).
(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO
(h) For asphalt blowing operations, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) The quantity of asphalt blown.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit.
(4) The calculated annual CO
(i) For process vents subject to § 98.253(j), the owner or operator shall report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated with the emissions.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.
(4) The calculated annual CO
(j) For equipment leaks, storage tanks, uncontrolled blowdown systems, delayed coking units, and loading operations, the owner or operator shall report:
(1) The total quantity (in Million bbl) of crude oil plus the quantity of intermediate products received from off-site that are processed at the facility in the reporting year.
(2) The method used to calculate equipment leak emissions and the
(3) The cumulative annual CH
(4) The quantity of unstabilized crude oil received during the calendar year and the cumulative CH
(5) The cumulative annual CH
(6) The total number of delayed coking units at the facility, the number of delayed coking drums per unit, the dimensions and annual number of coke-cutting cycles for each drum, and the cumulative annual CH
(7) The quantity and types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessels in which the material is loaded.
(8) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any.
(9) The cumulative annual CH
(k) If you have a CEMS that measures CO
In addition to the records required by § 98.3(g), you must retain the records of all parameters monitored under § 98.255.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is any system of operation that manufactures phosphoric acid by reacting phosphate rock and acid.
You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CO
(b) You must report CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(c) You must determine the total emissions from the facility using Equation Z–2 of this section:
(a) Determine the inorganic carbon content of each batch of phosphate rock consumed in the production of phosphoric acid using the applicable test method in section IX of the “Book of Methods Used and Adopted by the Association of Florida Phosphate Chemists”, Seventh Edition, 1991.
(b) If more than one batch of phosphate rock is consumed in a month, use the highest inorganic carbon content measured during that month in Equation Z–1 of this subpart.
(c) Record the mass of phosphate rock consumed each month in each wet-process phosphoric acid process line.
There are no missing data procedures for wet-process phosphoric acid production facilities estimated according to § 98.263(b). A complete record of all measured parameters used in the GHG emissions calculations is required. A re-test must be performed if the data from the measurement are determined to be unacceptable.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section for each wet-process phosphoric acid production line:
(a) Annual phosphoric acid production by origin of the phosphate rock (metric tons).
(b) Annual phosphoric acid production by concentration of phosphoric acid produced (metric tons).
(c) Annual phosphoric acid production capacity.
(d) Annual arithmetic average percent inorganic carbon in phosphate rock from batch records.
(e) Annual average phosphate rock consumption from monthly measurement records (in metric tons).
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section for each wet-process phosphoric acid production facility:
(a) Total annual CO
(b) Phosphoric acid production (by origin of the phosphate rock) and concentration.
(c) Phosphoric acid production capacity (in metric tons/year).
(d) Number of wet-process phosphoric acid process lines.
(e) Monthly phosphate rock consumption (by origin of phosphate rock).
(f) Measurements of percent inorganic carbon in phosphate rock for each batch consumed for phosphoric acid production.
(g) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine).
(h) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), and operate coating and laminating processes.
(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (6) of this section:
(1) Chemical recovery furnaces at kraft and sodamills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).
(2) Chemical recovery combustion units at sulfite facilities.
(3) Chemical recovery combustion units at stand-alone semichemical facilities.
(4) Pulp mill lime kilns at kraft and soda facilities.
(5) Systems for adding makeup chemicals (CaCO
You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report the emissions listed in paragraphs (a) through (h) of this section:
(a) CO
(b) CO
(c) CO
(d) CO
(e) CO
(f) Emissions of CO
(g) Emissions of CH
(h) Emissions of CH
(a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO
(1) Calculate fossil fuel-based CO
(2) Calculate fossil fuel-based CH
(3) Calculate biogenic CO
(b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine CO
(1) Calculate fossil CO
(2) Calculate CH
(3) Calculate biogenic CO
(4) Calculate CH
(c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO
(1) Calculate CO
(2) Calculate CH
(3) Biogenic CO
(d) For makeup chemical use, you must calculate CO
(a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request.
(b) High heat values of black liquor must be determined once per month using TAPPI Method T 684. The mass of spent black liquor solids must be determined once per month using TAPPI Method T 650. Carbon analyses for spent pulping liquor must be determined once per month using ASTM method D5373–08.
(c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel and makeup chemical usage, including, but not limited, to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.
(d) Records must be made available upon request for verification of the calculations and measurements.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section:
(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any monthly measurements are determined to be invalid.
(b) For missing spent pulping liquor flow rates, use the lesser value of either the maximum fuel flow rate for the combustion unit, or the maximum flow
(c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates.
In addition to the information required by § 98.3(c), each annual report must contain the information in paragraphs (a) through (e) of this section for each GHG emission unit listed in § 98.270(b).
(a) Annual emissions of CO
(b) Total consumption of all biomass fuels by calendar quarter.
(c) Total annual quantity of spent liquor solids fired at the facility by calendar quarter.
(d) Total annual steam purchases.
(e) Total annual quantities of makeup chemicals (carbonates) used.
In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (h) of this section.
(a) GHG emission estimates (including separate estimates of biogenic CO
(b) Monthly total consumption of all biomass fuels for each biomass combustion unit.
(c) Monthly analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities.
(d) Monthly analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.
(e) Monthly quantities of spent liquor solids fired in each chemical recovery furnace and chemical recovery combustion unit.
(f) Monthly and annual steam purchases.
(g) Monthly and annual steam production for each biomass combustion unit.
(h) Monthly quantities of makeup chemicals used.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.
You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CO
(b) You must report CO
You must determine CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) Use Equation BB–1 of this section to calculate the facility-specific emissions factor for determining CO
(2) Use Equation BB–2 of this section to calculate CO
(c) You must determine annual process CH
(a) You must determine the quantity of petroleum coke consumed each quarter (tons coke/quarter).
(b) For CO
A complete record of all measured parameters used in the GHG emissions calculations is required. There are no missing value provisions for the carbon content factor or coke consumption. A re-test must be performed if the data from the quarterly carbon content measurements are determined to be unacceptable or not representative of typical operations.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section.
(a) Annual CO
(b) Annual production of silicon carbide (in metric tons).
(c) Annual capacity of silicon carbide production (in metric tons).
(d) Annual operating hours.
(e) Quarterly facility-specific emission factors.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for all silicon carbide production processes combined.
(a) Annual consumption of petroleum coke (in metric tons).
(b) Quarterly analyses of carbon content for consumed coke (averaged to an annual basis).
(c) Quarterly facility-specific emission factor calculations.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
A soda ash manufacturing facility is any facility with a manufacturing line that calcines trona to produce soda ash.
You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CO
(b) You must report the CO
You must determine CO
(a) Any soda ash manufacturing line that meets the conditions specified in § 98.33(b)(5)(iii)(A),(B), and (C), or § 98.33(b)(5)(ii)(A) through (F) shall calculate total CO
(b) If the facility does not measure total emissions with a CEMS, you must determine the total process emissions from the facility using Equation CC–1 of this section:
(c) Calculate the annual CO
(a) You must determine the inorganic carbon content of the trona or soda ash on a daily basis and determine the monthly average value for each soda ash manufacturing line.
(b) If you calculate CO
(c) If you calculate CO
(d) You must measure the mass of trona input or soda ash produced by each soda ash manufacturing line on a monthly basis using either belt scales or by weighing the soda ash at the truck or rail loadout points of your facility.
(e) You must keep a record of all trona consumed and soda ash production. You also must document the procedures used to ensure the accuracy of the monthly measurements of trona consumed soda ash production.
A complete record of all measured parameters used in the GHG emissions calculations is required. There are no missing value provisions for the carbon content of trona or soda ash. A re-test must be performed if the data from the daily carbon content measurements are determined to be unacceptable.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (f) of this section for each soda ash manufacturing line.
(a) Annual CO
(b) Number of soda ash manufacturing lines.
(c) Annual soda ash production (metric tons) and annual soda ash production capacity.
(d) Annual consumption of trona from monthly measurements (metric tons).
(e) Fractional purity (i.e., inorganic carbon content) of trona or soda ash (by daily measurements and by monthly average) depending on the components used in Equation CC–2 or CC–3 of this subpart).
(f) Number of operating hours in calendar year.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each soda ash manufacturing line.
(a) Monthly production of soda ash (metric tons).
(b) Monthly consumption of trona (metric tons).
(c) Daily analyses for inorganic carbon content of trona or soda ash (as fractional purity), depending on the components used in Equation CC–2 or CC–3 of this subpart.
(d) Number of operating hours in calendar year.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The electric power system source category includes electric power transmission and distribution systems that operate gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers containing sulfur-hexafluoride (SF6) or perfluorocarbons (PFCs).
You must report GHG emissions from electric power systems if the total nameplate capacity of SF
You must report total SF
(a) Gas-insulated substations.
(b) Circuit breakers.
(c) Switchgear.
(d) Gas-insulated lines.
(d) Electrical transformers.
(a) For each electric power system, you must estimate the annual SF
(b) The mass-balance method in paragraph (a) of this section shall be used to estimate emissions of PFCs from power transformers, substituting the relevant PFC(s) for SF
(a) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to Equation DD–1 to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in SF
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to SF
(b) Ensure the following QA/QC methods are employed throughout the year:
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 1 percent of the true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within 1 percent, of residual gas amounts in the cylinders returned to the gas supplier.
(2) Ensure that procedures are in place and followed to track and weigh all cylinders as they are leaving and entering storage. Cylinders shall be weighed on a scale that is certified to be accurate to within 1 percent of the true weight and the scale shall be recalibrated at least annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. All scales used to measure quantities that are to be reported under § 98.306 shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ISWM, ISDA, NCWM, or others). Alternatively, calibration procedures specified by the scale manufacturer may be used. Calibration shall be performed prior to the first reporting year.
(3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system).
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for SF
In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical:
(a) Nameplate capacity of equipment containing SF
(1) Existing as of the beginning of the year.
(2) New during the year.
(3) Retired during the year.
(b) Transmission miles (length of lines carrying voltages at or above 34.5 kV).
(c) SF
(d) SF
(e) SF
(f) SF
(g) SF
(h) SF
(i) SF
(j) SF
In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide.
You must report GHG emissions under this subpart if your facility
(a) You must report CO
(b) Report the CO
You must determine CO
(a) If the facility operates and maintains a continuous emission monitoring system (CEMS) that meets the conditions specififed in § 98.33(b)(5)(ii) or (iii), then you must calculate total CO
(b) If the facility does not measure total emissions with a CEMS, you must calculate the process CO
(c) You must determine the total CO
(a) You must measure your consumption of calcined petroleum coke either by weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption.
There are no missing data procedures for the measurement of petroleum coke consumption. A complete record of all measured parameters used in the GHG emissions calculations is required.
In addition to the information required by § 98.3(c), each annual report must contain the following information specified in paragraphs (a) through (e) for each titanium dioxide production line.
(a) Annual CO
(b) Annual consumption of calcined petroleum coke (metric tons).
(c) Annual production of titanium dioxide (metric tons).
(d) Annual production capacity of titanium dioxide (metric tons).
(e) Annual operating hours for each titanium dioxide process line.
In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a) through (e) of this section for each titanium dioxide production facility.
(a) Monthly production of titanium dioxide (metric tons).
(b) Production capacity of titanium dioxide (metric tons).
(c) Records of all calcined petroleum coke purchases.
(d) Records of monthly calcined petroleum coke consumption (metric tons).
(e) Annual operating hours for each titanium dioxide process line.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category consists of active underground coal mines and any underground mines under development that have operational pre-mining degasification systems. An underground coal mine is a mine at which coal is produced by tunneling into the earth to a subsurface coal seam, where the coal is then mined with equipment such as cutting machines, and transported to the surface. Active underground coal mines are mines categorized by MSHA as active and where coal is currently being produced or has been produced within the previous 90 days.
(b) This source category comprises the following emission points:
(1) Each ventilation well or shaft.
(2) Each degasification system well or shaft, including degasification systems deployed before, during, or after mining operations are conducted in a mine area.
(c) This source category does not include abandoned (closed) mines, surface coal mines, or post-coal mining activities.
You must report GHG emissions under this subpart if your facility contains a underground coal mining process and the facility meets the requirements of either § 98.2(a)(1) or (2).
You must report the following:
(a) CH
(b) CO
(c) CO
(a) For each ventilation well or shaft, you must estimate the quarterly CH
(b) For each degasification system, you must estimate the quarterly CH
(c) If gas from degasification system wells or ventilation shafts is destroyed you must calculate the quarterly CH
(d) You must calculate the quarterly net CH
(e) For each degasification or ventilation system with on-site coal mine gas CH
(a) The flow and CH
(b) For liberation of methane from ventilation systems, you must do one of the following:
(1) Monitor emissions from each well or shaft where active ventilation is taking place by collecting quarterly grab samples and making quarterly measurements of flow rate, temperature, and pressure. The sampling and measurements must be made at the same location as MSHA inspection samples are taken. You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, General Coal Mine Inspection Procedures and Inspection Tracking System Handbook Number: PH–08–V–1, January 1, 2008. You must record the airflow, temperature, and pressure measured, the hand-held methane and oxygen readings in percentile, the bottle number of samples collected, and the location of the measurement or collection.
(2) Obtain results of the quarterly testing performed by MSHA.
(c) For liberation of methane at degasification systems, you must monitor methane concentrations and flow rate from each degasification well or shaft using any of the oil and gas flow
(d) All fuel flow meters and gas composition monitors monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, AGA, MSHA, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters, and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer or other applicable standards.
(e) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters, and other measurement devices. The estimated accuracy of measurements, and the technical basis for the estimated accuracy shall be recorded.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b) For each missing value of CH
In addition to the information required by § 98.3(c), each annual report must contain the following information for each mine:
(a) Quarterly volumetric flow rate measurement results for all ventilation systems, including date and location of measurement.
(b) Quarterly CH
(c) Quarterly CEMS volumetric flow data used to calculate CH
(d) Quarterly CEMS CH
(e) Quarterly CH
(f) Dates in reporting period where active ventilation of mining operations is taking place.
(g) Dates in reporting period when continuous monitoring equipment is not properly functioning.
(h) Quarterly averages of temperatures and pressures at the time and at the conditions for which all measurements are made.
(i) Quarterly CH
(j) Quarterly CH
(k) Quarterly CO
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Calibration records for all monitoring equipment.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.
You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report the CO
(a) You must report the CO
(a) If you operate and maintain a CEMS that measures total CO
(b) If you do not operate and maintain a CEMS that measures total CO
(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each calendar month and estimate total annual CO
(2) You must determine the total CO
If you determine CO
(a) Determine the mass of each solid carbon-containing input material by direct measurement of the quantity of the material placed in the unit or by calculations using process operating information, and record the total mass for the material for each calendar month.
(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material for each calendar month using information provided by your material supplier or by collecting and analyzing a representative sample of the material using an analysis method appropriate for the material.
(c) For each input material identified in paragraph (a) of this section for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed by an independent certified laboratory each calendar month using the test methods (and their QA/QC procedures) in § 98.7. Use ASTM E1941–04 (“Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”) for analysis of zinc bearing materials; ASTM D5373–02 (“Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”) for analysis of carbonaceous reducing agents and carbon electrodes, and ASTM C25–06 (“Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”) for analysis of flux materials such as limestone or dolomite.
For the carbon input procedure in § 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input material consumption, the substitute data value shall be the best available estimate of the mass of the input material. The owner or operator shall document and keep records of the procedures used for all such estimates.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section for each Waelz kiln or electrothermic furnace.
(a) Annual CO
(b) Annual zinc product production capacity (in metric tons).
(c) Total number of Waelz kilns and electrothermic furnaces at the facility.
(d) Number of facility operating hours in calendar year.
(e) If you use the carbon input procedure, report for each carbon-containing input material consumed or used (other than fuel), the information specified in paragraphs (e)(1) and (2) of this section.
(1) Annual material quantity (in metric tons).
(2) Annual average of the monthly carbon content determinations for each material and the method used for the determination (e.g., supplier provided information, analyses of representative samples you collected).
In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (d) of this section.
(a) Monthly facility production quantity for each zinc product (in metric tons).
(b) Number of facility operating hours each month.
(c) Annual production Quantity for each zinc product (in metric tons).
(d) If you use the carbon input procedure, record for each carbon-containing input material consumed or used (other than fuel), the information specified in paragraphs (d)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and records of the supplier provided information or analyses used for the determination.
(e) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each Waelz kiln or electrothermic furnace, as applicable to your facility. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category consists of the following sources at municipal solid waste (MSW) landfill facilities: landfills, landfill gas collection systems, and landfill gas combustion systems (including flares). This source category also includes industrial landfills (including, but not limited to landfills located at food processing, pulp and paper, and ethanol production facilities).
(b) This source category does not include hazardous waste landfills and construction and demolition landfills.
You must report GHG emissions under this subpart if your facility contains a landfill process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report CH
(b) You must report CH
(c) You must report CO
(a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH
(1) Calculate annual modeled CH
(2) For years when material-specific waste quantity data are available, and for industrial waste landfills, apply Equation HH–1 of this section for each waste quantity type and sum the CH
(3) For years prior to reporting for which waste disposal quantities are not readily available for MSW landfills, W
(4) For industrial landfills, W
(i) Calculate the average waste disposal rate per unit of production for the first applicable reporting year using Equation HH–2 of this section.
(ii) Calculate the waste disposal quantities for historic years in which direct waste disposal measurements are not available using historical production data and Equation HH–3 of this section.
(b) For landfills with gas collection systems, calculate the quantity of CH
(1) Measure continuously the flow rate, CH
(2) Calculate the quantity of CH
(c) Calculate CH
(1) Calculate CH
(2) For landfills that do not have landfill gas collection systems, the CH
(3) For landfills with landfill gas collection systems, calculate CH
(i) Calculate CH
(ii) Calculate CH
(a) The quantity of waste landfilled must be determined using mass measurement equipment meeting the requirements for commercial weighing equipment as described in “Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices” NIST Handbook 44, 2008.
(b) The quantity of landfill gas CH
(c) All fuel flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using ASTM D1945–03 (Reapproved 2006), Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946–90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or UOP539–97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters, and gas composition monitors shall be recalibrated either annually or at the minimum frequency specified by the manufacturer.
(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section.
(a) For each missing value of the CH
(b) For missing gas flow rates, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(c) For missing daily waste disposal data for disposal in reporting years, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) Waste disposal for each year of landfilling.
(b) Method for estimating waste disposal.
(c) Waste composition, if available, in percentage categorized as—
(1) Municipal,
(2) Construction and demolition,
(3) Biosolids or biological sludges,
(4) Industrial, inorganic,
(5) Industrial, organic,
(6) Other, or more refined categories, such as those for which k rates are available in Table HH–1 of this subpart.
(d) Method for estimating waste composition.
(e) Fraction of CH
(f) Oxidation fraction used in the calculations.
(g) Degradable organic carbon (DOC) used in the calculations.
(h) Decay rate k used in the calculations.
(i) Fraction of DOC dissimilated used in the calculations.
(j) Methane correction factor used in the calculations.
(k) Annual methane generation and methane emissions (metric tons/year) according to the methodologies in § 98.343(c)(1) through (3). Landfills with gas collection system must separately report methane generation and emissions according to the methodologies in § 98.343(c)(3)(i) and (ii) and indicate which values are calculated using the methodologies in § 98.343(c)(ii).
(l) Landfill design capacity.
(m) Estimated year of landfill closure.
(n) Total volumetric flow of landfill gas for landfills with gas collection systems.
(o) CH
(p) Monthly average temperature at which flow is measured for landfills with gas collection systems.
(q) Monthly average pressure at which flow is measured for landfills with gas collection systems.
(r) Destruction efficiency used for landfills with gas collection systems.
(s) Methane destruction for landfills with gas collection systems (total annual, metric tons/year).
(t) Estimated gas collection system efficiency for landfills with gas collection systems.
(u) Methodology for estimating gas collection system efficiency for landfills with gas collection systems.
(v) Cover system description.
(w) Number of wells in gas collection system.
(x) Acreage and quantity of waste covered by intermediate cap.
(y) Acreage and quantity of waste covered by final cap.
(z) Total CH
(aa) Total CH
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) A wastewater treatment system is the collection of all processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from waters released from industrial processes. This source category applies to on-site wastewater treatment systems at pulp and paper mills, food processing plants, ethanol production plants, petrochemical facilities, and petroleum refining facilities.
(b) This source category does not include centralized domestic wastewater treatment plants.
You must report GHG emissions under this subpart if your facility contains a wastewater treatment process and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report annual CH
(b) You must report annual CO
(c) You must report CO
(a) Estimate the annual CH
(b) For each petroleum refining facility having an on-site oil/water separator, estimate the annual CO
(c) For each anaerobic digester, estimate the annual mass of CH
(a) The quantity of COD treated anaerobically must be determined using analytical methods for industrial wastewater pollutants and must be conducted in accordance with the methods specified in 40 CFR part 136.
(b) All flow meters must be calibrated using the procedures and frequencies specified by the device manufacturer.
(c) For anaerobic treatment systems, facilities must monitor the wastewater flow and COD no less than once per week. The sample location must represent the influent to anaerobic treatment for the time period that is monitored. The flow sample must correspond to the location used to measure the COD. Facilities must collect 24-hour flow-weighted composite samples, unless they can demonstrate that the COD concentration and wastewater flow into the anaerobic treatment system does not vary. In this case, facilities must collect 24-hour time-weighted composites to characterize changes in wastewater due to production fluctuations, or a grab sample if the influent flow is equalized resulting in little variability.
(d) For oil/water separators, facilities must monitor the flow no less than once per week. The sample location must represent the influent to oil/water separator for the time period that is monitored.
(e) The quantity of gas destroyed must be determined using any of the oil and gas flow meter test methods incorporated by reference in § 98.7.
(f) All gas flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (
(g) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the device manufacturer.
(h) All equipment (temperature and pressure monitors and gas flow meters and gas composition monitors) shall be maintained as specified by the manufacturer.
(i) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (
(a) For each missing monthly value of COD or wastewater flow treated, the substitute data value shall be the arithmetic average of the quality-assured values of those parameters for the weeks immediately preceding and immediately following the missing data incident. For each missing value of the CH
(b) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
In addition to the information required by § 98.3(c), each annual report must contain the following information for the wastewater treatment system.
(a) Type of wastewater treatment system.
(b) Percent of wastewater treated at each system component.
(c) COD.
(d) Influent flow rate.
(e) B
(f) MCF.
(g) Methane emissions.
(h) Type of oil/water separator (petroleum refineries).
(i) Emissions factor for the type of separator (petroleum refineries).
(j) Carbon fraction in NMVOC (petroleum refineries).
(k) CO
(l) Total volumetric flow of digester gas (facilities with anaerobic digesters).
(m) CH
(n) Temperature at which flow is measured (facilities with anaerobic digesters).
(o) Pressure at which flow is measured (facilities with anaerobic digesters).
(p) Destruction efficiency used (facilities with anaerobic digesters).
(q) Methane destruction (facilities with anaerobic digesters).
(r) Fugitive methane (facilities with anaerobic digesters).
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category consists of manure management systems for livestock manure.
(b) A manure management system is as a system that stabilizes or stores livestock manure in one or more of the following system components: uncovered anaerobic lagoons, liquid/slurry systems, storage pits, digesters, drylots, solid manure storage, feedlots and other dry lots, high rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, and manure composting. This definition of manure management system encompasses the treatment of wastewaters from manure.
(c) This source category does not include components at a livestock operation unrelated to the stabilization or storage of manure such as daily spread or pasture/range/paddock systems.
You must report GHG emissions under this subpart if your facility contains a manure management system and the facility meets the requirements of either § 98.2(a)(1) or (2).
(a) You must report annual aggregate CH
(1) Liquid/slurry systems such as tanks and ponds.
(2) Storage pits.
(3) Uncovered anaerobic lagoons used for stabilization or storage or both.
(4) Digesters, including covered anaerobic lagoons.
(5) Solid manure storage including feedlots and other dry lots, high rise houses for caged laying hens, broiler and turkey production on litter, and deep bedding systems for cattle and swine.
(6) Manure composting.
(b) You must report CO
(c) A facility that is subject to this rule only because of emissions from manure management systems is not required to report emissions from fuels used in stationary combustion devices other than flares.
(a) For manure management systems except digesters, estimate the annual CH
(b) For each digester, estimate the annual CH
(c) For each manure management system type, estimate the annual N
(d) Estimate the annual total annual emissions using Equation JJ–8 of this section.
(a) Perform a one-time analysis on your operation to determine the percent of total manure by weight that is managed in each on-site manure management system.
(b) Determine the annual average percent total volatile solids by animal type, (%TVS) by analysis of a representative sample using Method 160.4 (Residue, Volatile) as described in Methods for Chemical Analysis of Water and Wastes, EPA–600/4–79/020, Revised March 1983. The laboratory performing the analyses should be certified for analysis of waste for National Pollutant Discharge Elimination System compliance reporting. The sample analyzed should be a representative composite of freshly excreted manure from each animal type contributing to the manure management system. Total volatile solids of manure must be sampled and analyzed monthly.
(c) Determine the annual average percent of nitrogen present in manure by animal type (N
(d) The flow and CH
(e) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(f) All gas flow meters and gas composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization (
(g) All equipment (temperature and pressure monitors and gas flow meters and gas composition monitors) shall be maintained as specified by the manufacturer.
(h) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section.
(b) For missing gas flow rates, volatile solids, or nitrogen or methane content data, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
In addition to the information required by § 98.3(c), each annual report
(a) Type of manure management system component.
(b) Animal population (by animal type).
(c) Monthly total volatile solids content of excreted manure.
(d) Percent of manure handled in each manure management system component.
(e) B
(f) Methane conversion factor used.
(g) Average animal mass (for each type of animal).
(h) Monthly nitrogen content of excreted manure.
(i) N
(j) CH
(k) N
(l) Total annual volumetric biogas flow (for systems with digesters).
(m) Average annual CH
(n) Temperature at which gas flow is measured (for systems with digesters).
(o) Pressure at which gas flow is measured (for systems with digesters).
(p) Destruction efficiency used (for systems with digesters).
(q) Methane destruction (for systems with digesters).
(r) Methane generation from the digesters.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) This source category comprises coal mines, coal importers, coal exporters, and waste coal reclaimers.
(b)
(c) Coal importer has the same meaning given in § 98.6 and includes any U.S. coal mining company, wholesale coal dealer, retail coal dealer, or other organization that imports coal into the U.S. “Importer” includes the person primarily liable for the payment of any duties on the merchandise or an authorized agent acting on his or her behalf.
(d) Coal exporter has the same meaning given in § 98.6 and includes any U.S. coal mining company, wholesale coal dealer, retail coal dealer, or other organization that exports coal from the U.S.
(e)
Any supplier of coal who meets the requirements of § 98.2(a)(4) must report GHG emissions.
You must report the CO
(a) For coal mines producing 100,000 short tons of coal or more annually, the estimate of CO
(b) For coal mines producing less than 100,000 short tons of coal annually, and for coal exporters, coal importers, and waste coal reclaimers; CO
(c) For Calculation Methodology 1, 2, and 3 of this subpart, emissions of CO
(d) For coal mines using Calculation Methodology 1 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be based on daily measurements and calculated using Equation KK–2 of this section. For importers, exporters, and waste coal reclaimers using Methodology 1 of this subpart, measurements of each shipment can be used in place of daily measurements:
(e) For coal mines using Calculation Methodology 2 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be calculated on the basis of daily measurements of the gross calorific value (GCV) of the coal and a statistical relationship between carbon content and GCV (higher heating value). For importers, exporters, and waste coal reclaimers using Calculation Methodology 2 of this subpart, measurements of each shipment can be used in place of daily measurements.
(1) Equation KK–3 shall be used to determine the weighted annual average GCV of the coal, and the individual daily or per shipment values shall be determined according to the monitoring methodology for gross calorific values in § 98.374(f).
(2) The statistical relationship between GCV and carbon content shall be established according to the requirements in § 98.374(f).
(3) The estimated annual weighted average of the mass fraction of carbon in the coal shall be calculated by applying the slope coefficient, determined according to the requirements of § 98.374(f)(4), to the weighted annual average GCV of the coal determined according to Equation KK–3 of this section.
(f) For coal mines using Calculation Methodology 3 of this subpart, the annual weighted average of the mass fraction of carbon in the coal shall be calculated on the basis of daily measurements of GCV of the coal and a default fraction of carbon in coal from Table KK–1 of this subpart. For importers, exporters, and waste coal reclaimers using Methodology 3 of this subpart, measurements of each shipment can be used in place of daily measurements.
(1) Equation KK–3 shall be used to determine the weighted annual average
(2) The estimated annual weighted average of the mass fraction of carbon in the coal shall be identified from Table KK–1 of this subpart using annual weighted GCV of the coal determined according to Equation KK–3 of this section.
(g) For Calculation Methodologies 2 and 3 of this subpart, the weighted annual average gross calorific value (GCV) or higher heating value of the coal shall be calculated using Equation KK–3 of this section:
(a) The most current version of the NIST Handbook published by Weights and Measures Division, National Institute of Standards and Technology shall be used as the standard practice for all coal weighing.
(b) For all coal mines, the quantity of coal shall be determined as the total mass of coal in short tons sold and removed from the facility during the calendar year.
(c) For coal importers, the quantity of coal shall be determined as the total mass of coal in short tons imported into the U.S. during the calendar year, as reported to U.S. Customs.
(d) For coal exporters, the quantity of coal shall be determined as the total mass of coal in short tons sold and exported from the U.S., as reported to U.S. Customs.
(e) For waste coal reclaimers, the quantity of coal shall be determined as the total mass of coal in short tons sold for use as reported to state agencies.
(f) For reporters using Calculation Methodology 1 of this subpart, the carbon content shall be determined as follows:
(1) Representative coal samples shall be collected daily or per shipment using ASTM D4916–04, D6609–07, D6883–04, D7256/D7256M–06a, or D7430–08 from coal loaded on the conveyor belt.
(2) Daily or per shipment coal carbon content shall be determined using ASTM D5373 (Test Methods for Instrumental Determination of Carbon Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke).
(g) For reporters using Calculation Methodology 2 of this subpart, the carbon content shall be determined as follows:
(1) Representative samples of coal shall be collected daily or per shipment using ASTM D4916–04, D6609–07, D6883–04, D7256/D7256M–06a, or D7430–08.
(2) Coal gross calorific value (GCV) shall be determined on the set of samples collected in paragraph (f)(1) of this section using ASTM D5865–07a, “Standard Test Method for Gross Calorific Value of Coal and Coke to record the heat content of the coal produced.
(3) Coal carbon content shall be determined at a minimum once each month on one set of daily or per shipment samples collected in paragraph (f)(1) of this section using ASTM D5373 (Test Methods for Instrumental Determination of Carbon Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke).
(4) The individual samples for which both carbon content and GCV were determined according to paragraphs (f)(2) and (f)(3) of this section respectively, shall be used to establish a statistical relationship between the heat content and the carbon content of the coal produced. The owner or operator shall statistically plot the correlation of Btu/lb of coal vs. percent carbon (as a decimal value), where the x-axis is Btu/lb coal and the y-axis is percent carbon (as decimal value), then fit a line to the data points, then calculate the slope and the coefficient of determination, and the R-square (R
(5) Calculation Methodology 2 of this subpart can be used only if all of the following four conditions are met:
(i) At least 12 samples per reporting year from 12 different months of data must be used to construct the correlation graph.
(ii) The correlation graph must be constructed using all paired data points from the first reporting year and all subsequent reporting years.
(iii) There must be a linear relationship between percent carbon and Btu/lb of coal.
(iv) For the second and subsequent years, R-square (R
(6) If all of the conditions specified in paragraph (f)(5) of this section are met, the weighted annual average gross calorific value or higher heating value (Btu/lb) calculated according to Equation KK–3 of this section shall be used to determine the corresponding annual average coal carbon content using the correlation graph plotted according to paragraph (f)(4) of this section.
(h) Reporters complying with Calculation Methodology 3 of this subpart shall determine gross calorific value of the coal by collecting representative daily or per shipment samples of coal using either ASTM D4916–04, D6609–07, D6883–04, D7256/D7256M–06a, or D7430–08; and testing using ASTM D5865–07a, “Standard Test Method for Gross Calorific Value of Coal and Coke to record the heat content of the coal produced.”
(i) Coal exporters shall calculate carbon content for each shipment of coal using information on the carbon content of the exported coal provided by the source mine, according to Calculation Methodology 1, 2, or 3 of this subpart, as appropriate.
(j) Coal importers shall calculate carbon content for each shipment of coal using Calculation Methodology 1, 2, or 3 of this subpart.
(k) Waste coal reclaimers shall calculate carbon content for each shipment of coal using Calculation Methodology 1, 2, or 3 of this subpart.
(l) Each owner or operator using mechanical coal sampling systems shall perform quality assurance and quality control according to ASTM D4702–07 and ASTM D6518–07.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations.
(b) Whenever a quality-assured value for coal production during any time period is unavailable, you must use the average of the parameter values recorded immediately before and after the missing data period in the calculations.
(c) Facilities using Calculation Methodology 1 of this subpart shall develop the statistical relationship between GCV and carbon content according to § 98.274(e), and use this statistical relationship to estimate daily carbon content for any day for which
(d) Facilities, importers and exporters using Calculation Methodology 2 or 3 of this subpart shall estimate the missing GCV values based on a weighted average value for the previous seven days.
(e) Estimates of missing data shall be documented and records maintained showing the calculations.
In addition to the information required by § 98.3(c), each annual report must contain the following information.
(a) Each coal mine owner or operator shall report the following information for each coal mine:
(1) The name and MSHA ID number of the mine.
(2) The name of the operating company.
(3) Annual CO
(4) By rank, the total annual quantity in tons of coal produced.
(5) The annual weighted carbon content of the coal as calculated according to § 98.373.
(6) If Calculation Methodology 1 of this subpart was used to determine CO
(7) If Calculation Methodology 2 of this subpart was used to determine CO
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R
(8) If Calculation Methodology 3 of this subpart was used to determine CO
(b) Coal importers shall report the following information at the corporate level:
(1) The total annual quantity in tons of coal imported into the U.S. by the importer, by rank, and country of origin.
(2) Annual CO
(3) The annual weighted carbon content of the coal as calculated according to § 98.373.
(4) If Calculation Methodology 1 of this subpart was used to determine CO
(5) If Calculation Methodology 2 of this subpart was used to determine CO
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R
(6) If Calculation Methodology 3 of this subpart was used to determine CO
(d) Coal exporters shall report the following information at the corporate level:
(1) The total annual quantity in tons of coal exported from the U.S. by rank and by coal producing company and mine.
(2) Annual CO
(3) The annual weighted carbon content of the coal as calculated according to § 98.373.
(4) If Calculation Methodology 1 of this subpart was used to determine CO
(5) If Calculation Methodology 2 of this subpart was used to determine CO
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R
(6) If Calculation Methodology 3 of this subpart was used to determine CO
(e) Waste coal reclaimers shall report the following information for each reclamation site:
(1) By rank, the total annual quantity in tons of waste coal produced.
(2) Mine and state of origin if waste coal is reclaimed from mines that are no longer operating.
(3) Annual CO
(4) The annual weighted carbon content of the coal as calculated according to § 98.373.
(5) If Calculation Methodology 1 of this subpart was used to determine CO
(6) If Calculation Methodology 2 of this subpart was used to determine CO
(i) All of the data used to construct the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squre (R
(7) If Calculation Methodology 3 of this subpart was used to determine CO
In addition to the records required by § 98.3(g), you must retain the following information:
(a) A complete record of all measured parameters used in the reporting of fuel quantities, including all sample results and documentation to support quantities that are reported under this part.
(b) Records documenting all calculations of missing data.
(c) Calculations and worksheets used to estimate the CO
(d) Calibration records of any instruments used on site and calibration records of scales or other equipment used to weigh coal.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This source category consists of producers, importers, and exporters of coal-based liquids.
(a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in coverting coal into liquid fuels such as gasoline and diesel using the Fischer-Tropsch process or an alternative process, involving conversion of coal into gas and then into liquids or conversion of coal directly into liquids (direct liquefaction).
(b) An importer or exporter shall have the same meaning given in § 98.6.
Any supplier of coal-based liquid fuels who meets the requirements of § 98.2(a)(4) must report GHG emissions.
You must report the CO
(a) Coal-to-liquid producers, importers and exporters must calculate CO
(b) The emission factor (EF) for each type of coal-based liquid shall be determined using either of the calculation methodologies described in paragraphs (a) and (b) of this section. The same calculation methodology must be used for the entire volume of the product for the reporting year.
(1)
(2)
(a) Producers must measure the quantity of coal-based liquid fuels using procedures for flow meters as described in subpart MM of this part.
(b) Importers and exporters must determine the quantity of coal-based liquid fuels using sales contract information on the volume imported or exported during the reporting period.
(1) The quantity of coal-based liquid fuels must be measured using sales contract information.
(2) The minimum frequency of the measurement of quantities of coal-based liquid fuels shall be the number of sales contracts executed in the reporting period.
(c) All flow meters and product monitors shall be calibrated prior to use for reporting, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, NAESB, or others). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters shall be recalibrated either annually or at the minimum frequency specified by the manufacturer.
(d) Reporters shall take the following steps to ensure the quality and accuracy of the data reported under these rules:
(1) For all volumes of coal-based liquid fuels, reporters shall maintain meter and such other records as are normally maintained in the course of business to document fuel flows.
(2) For all estimates of CO
(a) A complete record of all measured parameters used in the reporting of fuel volumes and the calculations of CO
(b) For coal-to-liquids facilities, the last quality assured reading shall be
(c) Calculation of substitute data shall be documented and records maintained showing the calculations.
In addition to the information required by § 98.3(c), each annual report must contain the following information:
(a) Producers shall report the following information for each facility:
(1) The total annual volume of each coal-based liquid supplied to the economy (in standard barrels).
(2) The total annual CO
(b) Importers shall report the following information at the corporate level:
(1) The total annual volume of each imported coal-based liquid (in standard barrels).
(2) The total annual CO
(c) Exporters shall report the following information at the corporate level:
(1) The total annual volume of each exported coal-based liquid (in standard barrels).
(2) The total annual CO
Reporters shall retain copies of all reports submitted to EPA. Reporters shall maintain records to support volumes that are reported under this part, including records documenting any calculation of substitute measured data. Reporters shall also retain calculations and worksheets used to estimate the CO
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This source category consists of petroleum refineries and importers and exporters of petroleum products.
(a) A petroleum refinery is any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives.
(b) A refiner is the owner or operator of a petroleum refinery.
(c) Importer has the same meaning given in § 98.6 and includes any blender or refiner of refined or semi-refined petroleum products.
(d) Exporter has the same meaning given in § 98.6 and includes any blender or refiner of refined or semi-refined petroleum products.
Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
You must report the CO
(a) Except as provided in paragraph (g) of this section, any refiner, importer, or exporter shall calculate CO
(b) Except as provided in paragraph (g) of this secton, any refiner shall calculate CO
(c) Refiners shall calculate CO
(d) Refiners shall calculate total CO
(e) Importers and exporters shall calculate total CO
(f) Except as provided in paragraph (g) of this section, the emission factor (EF) for each petroleum product and natural gas liquid shall be determined using either of the calculation methodologies described in paragraphs (f)(1) or (f)(2) of this section. The same calculation methodology must be used for the entire volume of the product for the reporting year.
(1)
(2)
(g) In the event that some portion of a petroleum product or feedstock is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together (i.e., the petroleum product or feedstock was produced by blending a petroleum-based product with a biomass-based product), the reporting party shall calculate emissions for the petroleum product or feedstock according to one of the methods in paragraph (g)(1) or (2) of this section, as appropriate.
(1) A reporting party using Calculation Methodology 1 of this subpart to determine the emission factor of a petroleum product shall calculate the CO
(2) A refinery using Calculation Methodology 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO
(3) A reporter using Calculation Methodology 2 of this subpart to determine the emission factor of a petroleum product must calculate the CO
(4) A refiner using Calculation Methodology 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock must calculate the CO
(h) Refiners shall use the most appropriate default CO
(a) The quantity of petroleum products, natural gas liquids, biomass, and all feedstocks shall be determined using either a flow meter or tank gauge, depending on the reporters existing equipment and preferences.
(1) For flow meters any one of the following test methods can be used to determine quantity:
(i) Ultra-sonic flow meter:
(ii) Turbine meters: American National Standards Institute,
(iii) Orifice meters: American National Standards Institute,
(iv) Coriolis meters:
(2) For tank gauges any one of the following test methods can be used to determine quantity:
(i) API–2550: Measurements and Calibration of Petroleum Storage Tanks (1965)
(ii) API MPMS 2.2: A Manual of Petroleum Measurement Standards (1995)
(iii) API–653: Tank Inspection, Repair, Alteration and Reconstruction, 3rd edition (2008)
(b) All flow meters and tank gauges shall be calibrated prior to use for reporting, using a suitable method published by a consensus standards organization (e.g., ASTM, ASME, API, or NAESB). Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Product flow meters and tank gauges shall be recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.
(c) For Calculation Methodology 2 of this subpart, samples of each petroleum product and natural gas liquid shall be taken each month for the reporting year. The composite sample shall be tested at the end of the reporting year using ASTM D1298 (2003), ASTM D1657–02 (2007), ASTM D4052–96 (2002)el, ASTM D5002–99 (2005), or ASTM D5004–89 (2004)el for density, as appropriate, and ASTM D5291 (2005) or ASTM D6729–(2004)el for carbon share, as appropriate (see Technical Support Document). Reporters must sample seasonal gasoline each month of the season and then test the composite sample at the end of the season.
Whenever a metered or quality-assured value of the quantity of petroleum products, natural gas liquids, biomass, or feedstocks during any period is unavailable, a substitute data value for the missing quantity measurement shall be used in the calculations contained in § 98.393.
(a) For marine-imported and exported refined and semi-refined products, the reporting party shall attempt to reconcile any differences between ship and shore volume readings. If the reporting party is unable to reconcile the readings, the higher of the two volume values shall be used for emission calculation purposes.
(b) For pipeline imported and exported refined and semi-refined products, the last valid volume reading based on the company's established procedures for purposes of product tracking and billing shall be used. If the pipeline experiences substantial variations in flow rate, the average of the last valid volume reading and the next valid volume reading shall be used for emission calculation purposes.
(c) For petroleum refineries, the last valid volume reading based on the facility's established procedures for purposes of product tracking and billing shall be used. If substantial variation in the flow rate is observed, the average of the last and the next valid volume reading shall be used for emission calculation purposes.
In addition to the information required by § 98.3(c), the following requirements apply.
(a) Refiners shall report the following information for each facility:
(1) CO
(2) CO
(3) CO
(4) The total sum of CO
(5) The total volume of each petroleum product and natural gas liquid associated with the CO
(6) The total volume of any biomass co-processed with a petroleum product associated with the CO
(7) The measured density and/or mass carbon share for any petroleum product or natural gas liquid for which CO
(8) The total volume of each distillate fuel oil product or feedstock reported in paragraph (a)(5) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164.
(9) All of the following information for all crude oil feedstocks used at the refinery:
(i) Batch volume (in standard barrels).
(ii) API gravity of the batch.
(iii) Sulfur content of the batch.
(iv) Country of origin of the batch.
(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:
(1) CO
(2) Total sum of CO
(3) The total volume of each imported petroleum product and natural gas liquid associated with the CO
(4) The measured density and/or mass carbon share for any imported petroleum product or natural gas liquid for which CO
(5) The total volume of each distillate fuel oil product reported in paragraph (b)(1) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164.
(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:
(1) CO
(2) Total sum of CO
(3) The total volume of each exported petroleum product and natural gas liquid associated with the CO
(4) The measured density and/or mass carbon share for any petroleum product or natural gas liquid for which CO
(5) The total volume of each distillate fuel oil product reported in paragraph (c)(1) of this section that contains less than 15 ppm sulfur content and is free from marker solvent yellow 124 and dye solvent red 164.
(a) Any reporter described in § 98.391 shall retain copies of all reports submitted to EPA under § 98.396. In addition, any reporter under this subpart shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products.
(b) Reporters shall maintain records to support volumes that are reported under this part, including records documenting any estimations of missing metered data. For all volumes of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain meter and other records normally maintained in the course of business to document product and feedstock flows.
(c) Reporters shall also retain laboratory reports, calculations and worksheets used to estimate the CO
(d) Estimates of missing data shall be documented and records maintained showing the calculations.
(e) Reporters described in this subpart shall also retain all records described in § 98.3(g).
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
This supplier category consists of natural gas processing plants and local natural gas distribution companies.
(a) Natural Gas Processing Plants are installations designed to separate and recover natural gas liquids (NGLs) or other gases and liquids from a stream of produced natural gas through the processes of condensation, absorption, adsorption, refrigeration, or other methods and to control the quality of natural gas marketed. This does not include field gathering and boosting stations.
(b) Local Distribution Companies are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems.
Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions.
(a) Natural gas processing plants must report the CO
(b) Local distribution companies must report the CO
(a) For each type of fuel or product reported under this part, calculate the estimated CO
(1)
(2)
(a) The quantity of natural gas liquids and natural gas must be determined
(b) The minimum frequency of the measurements of quantities of natural gas liquids and natural gas shall be based on the industry standard practices for commercial operations. For natural gas liquids these are measurements taken at custody transfers summed to the annual reportable volume. For natural gas these are daily totals of continuous measurements, and summed to the annual reportable volume.
(c) All flow meters and product or fuel composition monitors shall be calibrated prior to the first reporting year, using a suitable method published by the American Gas Association Gas Measurement Committee reports on flow metering and heating value calculations and the Gas Processors Association standards on measurement and heating value. Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Fuel flow meters shall be recalibrated either annually or at the minimum frequency specified by the manufacturer.
(d) Reporter-specific emission factors or higher heating values shall be determined using industry standard practices such as the American Gas Association (AGA) Gas Measurement Committee Report on heating value and the Gas Processors Association (GPA) Technical Standards Manual for NGL heating value; and ASTM D–2597–94 and ASTM D–1945–03 for compositional analysis necessary for estimating CO
(a) A complete record of all measured parameters used in the reporting of fuel volumes and in the calculations of CO
(b) For NGLs, natural gas processing plants shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the processing plant whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, natural gas processors may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties.
(c) Natural gas local distribution companies may substitute the metered quantities from the delivering pipelines for all deliveries into the distribution system. In cases where the pipeline metered delivery data are not available, local distribution companies may substitute their pipeline nominations and scheduled quantities for the period when metered values of actual deliveries are not available.
(d) Estimates of missing data shall be documented and records maintained showing the calculations of the values used for the missing data.
(a) In addition to the information required by § 98.3(c), the annual report for each natural gas processing plant must contain the following information.
(1) The total annual quantity in barrels of NGLs produced for sale or delivery on behalf of others in the following categories: Propane, natural butane, ethane, and isobutane, and all other bulk NGLs as a single category.
(2) The total annual CO
(b) In addition to the information required by § 98.3(c), the annual report for each local distribution company must contain the following information.
(1) The total annual volume in Mcf of natural gas received by the local distribution company for redelivery to end users on the local distribution company's distribution system.
(2) The total annual CO
(3) The total natural gas volumes received for redelivery to downstream gas transmission pipelines and other local distribution companies.
(4) The name and EPA and EIA identification code of each individual covered facility, and the name and EIA identification code of any other end-user for which the local gas distribution company delivered greater than or equal to 460,000 Mcf during the calendar year, and the total natural gas volumes actually delivered to each of these end-users.
(5) The annual volume in Mcf of natural gas delivered by the local distribution company to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 and Instructions.
(i) Residential consumers.
(ii) Commercial consumers.
(iii) Industrial consumers.
(iv) Electricity generating facilities.
(6) The total annual CO
In addition to the information required by § 98.3(g), each annual report must contain the following information:
(a) Records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part.
(b) Records documenting any estimates of missing metered data.
(c) Calculations and worksheets used to estimate CO
(d) Records related to the large end-users identified in § 98.406(b)(4).
(e) Records relating to measured Btu content or carbon content.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The industrial gas supplier source category consists of any facility that produces a fluorinated GHG or nitrous oxide, any bulk importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of fluorinated GHGs or nitrous oxide.
(b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHGs does not include the reuse or recycling of a fluorinated GHG or the generation of HFC–23 during the production of HCFC–22.
(c)
Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year.
(a) The total mass of each fluorinated GHG or nitrous oxide produced annually shall be estimated by using Equation OO–1 of this section:
(b) The total mass of each fluorinated GHG or nitrous oxide produced over the period “p” shall be estimated by using Equation OO–2 of this section:
(c) The total mass of each fluorinated GHG or nitrous oxide transformed shall be estimated by using Equation OO–3 of this section:
(d) The total mass of each fluorinated GHG destroyed shall be estimated by using Equation OO–4 of this section:
(a) The mass of fluorinated GHGs or nitrous oxide coming out of the production process shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better.
(b) The mass of any used fluorinated GHGs or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured at least daily (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better.
(c) The mass of fluorinated GHGs or nitrous oxide fed into transformation processes shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density
(d) If unreacted fluorinated GHGs or nitrous oxide are permanently removed (recovered, destroyed, or emitted) from the transformation process, the mass removed shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the unreacted fluorinated GHG or nitrous oxide, the concentration of the unreacted fluorinated GHG or nitrous oxide shall be measured at least daily using equipment and methods (
(e) The mass of fluorinated GHG or nitrous oxide sent to another facility for transformation shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better.
(f) The mass of fluorinated GHG sent to another facility for destruction shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG, the concentration of the fluorinated GHG shall be measured at least daily using equipment and methods (
(g) The mass of fluorinated GHGs fed into the destruction device shall be measured at least daily using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 0.2 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, the concentrations of fluorinated GHG being destroyed shall be measured at least daily using equipment and methods (
(h) For purposes of Equation OO–4, the destruction efficiency can initially be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device. Fluorinated GHG production facilities that destroy fluorinated GHGs shall conduct annual measurements of mass flow and fluorinated GHG concentrations at the outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A–6. Tests shall be conducted under conditions that are typical for the production process and destruction device at the facility. The sensitivity of the emissions tests shall be sufficient to detect emissions equal to 0.01 percent of the mass of fluorinated GHGs being fed into the destruction device. If the test indicates that the actual DE of the destruction device is lower than the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for the previously determined DE in the calculations in § 98.413, or
(2) Perform more extensive performance testing of the DE of the oxidizer and use the DE determined by the more extensive testing in the calculations in § 98.413.
(i) In their estimates of the mass of fluorinated GHGs destroyed, designated representatives of fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(j) All flowmeters, weigh scales, and combinations of volumetric and density measurements that are used to measure or calculate quantities that are to be reported under this subpart shall be calibrated using suitable NIST-traceable standards and suitable methods published by a consensus standards organization (
(k) All gas chromatographs that are used to measure or calculate quantities that are to be reported under this subpart shall be calibrated at least monthly through analysis of certified standards with known concentrations of the same chemical(s) in the same range(s) (fractions by mass) as the process samples. Calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Test Method 205, 40 CFR Part 51, Appendix M may also be used.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (
(1) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into transformation processes, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product.
(2) For each missing value of fluorinated GHG concentration, except the annual destruction device outlet concentration measurement specified in § 98.414(h), the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-
(3) Notwithstanding paragraphs (a)(1) and (2) of this section, if the owner or operator has reason to believe that the methods specified in paragraphs (a)(1) and (2) of this section are likely to significantly under- or overestimate the value of the parameter during the period when data were missing, the designated representative of the fluorinated GHG production facility shall develop his or her best estimate of the parameter, documenting the methods used, the rationale behind them, and the reasons why the methods specified in paragraphs (a)(1) and (2) of this section would probably lead to a significant under- or overestimate of the parameter. EPA may reject the alternative estimate and replace it with an estimate based on the applicable method in paragraph (a)(1) or (2) if EPA does not agree with the rationale or method for the alternative estimate.
In addition to the information required by § 98.3(c), each annual report must contain the following information:
(a) Each fluorinated GHG or nitrous oxide production facility shall report the following information at the facility level:
(1) Total mass in metric tons of each fluorinated GHG or nitrous oxide produced at that facility.
(2) Total mass in metric tons of each fluorinated GHG or nitrous oxide transformed at that facility.
(3) Total mass in metric tons of each fluorinated GHG destroyed at that facility.
(4) Total mass in metric tons of any fluorinated GHG or nitrous oxide sent to another facility for transformation.
(5) Total mass in metric tons of any fluorinated GHG sent to another facility for destruction.
(6) Total mass in metric tons of each reactant fed into the production process.
(7) Total mass in metric tons of each non-GHG reactant and by-product permanently removed from the process.
(8) Mass of used product added back into the production process (e.g., for reclamation).
(9) Names and addresses of facilities to which any nitrous oxide or fluorinated GHGs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for transformation.
(10) Names and addresses of facilities to which any fluorinated GHGs were sent for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for destruction.
(11) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data. Where the missing data have been estimated pursuant to § 98.415(a)(3), the report shall explain the rationale for the methods used to estimate the missing data and why the methods specified in § 98.415(a)(1) and (2) would lead to a significant under- or overestimate of the parameters.
(b) A fluorinated GHG production facility that destroys fluorinated GHGs shall report the results of the annual fluorinated GHG concentration measurements at the outlet of the destruction device, including:
(1) Flow rate of fluorinated GHG being fed into the destruction device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at the outlet of the destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate calculated from (b)(2) and (b)(3) in kg/hr.
(c) A fluorinated GHG production facility that destroys fluorinated GHGs shall submit a one-time report containing the following information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(d) A bulk importer of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their imports at the corporate level, except for transshipments and heels. The report shall contain the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs or nitrous oxide were imported.
(6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.
(7) Importer number for the shipment.
(8) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for transformation.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for destruction.
(e) A bulk exporter of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their exports at the corporate level, except for transshipments and heels. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG exported in bulk.
(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter's Employee Identification Number.
(4) Quantity exported by chemical in metric tons of chemical.
(5) Commodity code of the fluorinated GHGs and nitrous oxide shipped.
(6) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from the United States or its territories.
(7) Country to which the fluorinated GHGs or nitrous oxide were exported.
(a) In addition to the data required by § 98.3(g), the designated representative of a fluorinated GHG production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under § 98.416, and
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.414(j) and (k).
(b) In addition to the data required by paragraph (a) of this section, the designated representative of a fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report and annual destruction device outlet reports in § 98.416(b) and (c).
(c) In addition to the data required by § 98.3(g), the designated representative of a bulk importer shall retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by § 98.3(g), the designated representative of a bulk exporter shall retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the import.
(e) Every person who imports a container with a heel shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
(a) The carbon dioxide (CO
(1) Production process units that capture a CO
(2) Facilities with CO
(3) Importers or exporters of bulk CO
(b) This source category does not include the following:
(1) Geologic sequestration (long term storage) of CO
(2) Injection and subsequent production and/or processing of CO
(3) Above ground storage of CO
(4) Transportation or distribution of CO
(5) Purification, compression, or processing of CO
(6) CO
Any supplier of CO
You must report the mass of carbon dioxide captured from production process units, the mass of carbon dioxide extracted from carbon dioxide production wells, and the mass of carbon dioxide imported and exported regardless of the degree of impurities in the carbon dioxide stream.
(a) Facilities with production process units must calculate quarterly the total mass of carbon dioxide in a carbon dioxide stream in metric tons captured, prior to any subsequent purification, processing, or compressing, based on multiplying the mass flow by the composition data, according to Equation PP–1 of this section. Mass flow and composition data measurements are made in accordance with § 98.424.
(b) CO
(c) Importers or exporters of a carbon dioxide stream must calculate quarterly the total mass of carbon dioxide imported or exported in metric tons, based on multiplying the mass flow by the composition data, according to Equation PP–1. Mass flow and composition data measurements are made in accordance with § 98.424. The quantities of CO
(a) Facilities with production process units that capture a carbon dioxide stream must measure on a quarterly basis using a mass flow meter the mass flow of the CO
(b) Carbon dioxide production well facilities must measure on a quarterly basis the mass flow of the CO
(c) Importers or exporters of bulk CO
(d) Mass flow meter calibrations must be NIST traceable.
(e) Methods to measure the composition of the carbon dioxide captured, extracted, transferred, imported, or exported must conform to applicable chemical analytical standards. Acceptable methods include U.S. Food and Drug Administration food-grade specifications for carbon dioxide (see 21 CFR 184.1250) and ASTM standard E–1745–95 (2005).
(a) Missing quarterly monitoring data on mass flow of CO
(1) Quarterly CO
(2) Quarterly or annual average values of the monitored CO
(b) Missing monitoring data on the mass flow of the CO
(c) Missing data on composition of the CO
In addition to the information required by § 98.3(c), each annual report must contain the following information.
(a) Each facility with production process units or CO
(1) Total annual mass in metric tons and the weighted average composition of the CO
(2) Annual quantities in metric tons transferred to the following end use applications by end-use, if known:
(i) Food and beverage.
(ii) Industrial and municipal water/wastewater treatment.
(iii) Metal fabrication, including welding and cutting.
(iv) Greenhouse uses for plant growth.
(v) Fumigants (e.g., grain storage) and herbicides.
(vi) Pulp and paper.
(vii) Cleaning and solvent use.
(viii) Fire fighting.
(ix) Transportation and storage of explosives.
(x) Enhanced oil and natural gas recovery.
(xi) Long-term storage (sequestration).
(xii) Research and development.
(b) CO
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section.
(a) The owner or operator of a facility containing production process units must retain quarterly records of captured and transferred CO
(b) The owner or operator of a carbon dioxide production well facility must maintain quarterly records of the mass flow of the extracted and transferred CO
(c) Importers or exporters of CO
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
27. The authority citation for part 600 continues to read as follows:
49 U.S.C. 32901–23919q, Pub. L. 109–58.
28. Section 600.006–08 is amended by revising paragraph (c) introductory text and adding paragraph (c)(5) to read as follows:
(c) The manufacturer shall submit the following data:
(5) Starting with the 2011 model year, the data submitted according to paragraphs (c)(1) through (c)(4) of this section shall include CO
(i) Round CO
(ii) Round N
(iii) Round CH
29. The authority citation for part 1033 continues to read as follows:
42 U.S.C. 7401–7671q.
30. Section 1033.205 is amended by revising paragraph (d)(8) to read as follows:
(d) * * *
(8)(i) All test data you obtained for each test engine or locomotive. As described in § 1033.235, we may allow you to demonstrate compliance based on results from previous emission tests, development tests, or other testing information. Include data for NO
(ii) Starting in the 2011 model year, report measured N
31. Section 1033.235 is amended by adding paragraph (i) to read as follows:
(i) Starting in the 2011 model year, measure N
(1) Round CO
(2) Round N
(3) Round CH
32. Section 1033.905 is amended by adding the abbreviations CH
CH
N
33. The authority citation for part 1039 continues to read as follows:
42 U.S.C. 7401–7671q.
34. Section 1039.205 is amended by revising paragraph (r) to read as follows:
(r) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured CO
35. Section 1039.235 is amended by adding paragraph (g) to read as follows:
(g) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
36. Section 1039.805 is amended by adding the abbreviations CH
CH
N
37. The authority citation for part 1042 continues to read as follows:
42 U.S.C. 7401–7671q.
38. Section 1042.205 is amended by revising paragraph (r) to read as follows:
(r) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured CO
39. Section 1042.235 is amended by adding paragraph (g) to read as follows:
(g) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
40. Section 1042.905 is amended by adding the abbreviations CH
CH
N
41. The authority citation for part 1045 continues to read as follows:
42 U.S.C. 7401–7671q.
42. Section 1045.205 is amended by revising paragraph (q) to read as follows:
(q) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year, report measured CO
43. Section 1045.235 is amended by adding paragraph (g) to read as follows:
(g) Measure CO
(1) Round CO
(2) Round N
(3) Round CH
44. The authority citation for part 1048 continues to read as follows:
42 U.S.C. 7401–7671q.
45. Section 1048.205 is amended by revising paragraph (s) to read as follows:
(s) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured CO
46. Section 1048.235 is amended by adding paragraph (g) to read as follows:
(g) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
47. Section 1048.805 is amended by adding the abbreviations CH
CH
N
48. The authority citation for part 1051 continues to read as follows:
42 U.S.C. 7401–7671q.
49. Section 1051.205 is amended by revising paragraph (p) to read as follows:
(p) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 86 and 1065.
(2) Starting in the 2011 model year, report measured CO
50. Section 1051.235 is amended by adding paragraph (i) to read as follows:
(i) Starting in the 2011 model year, measure CO
(1) Round CO
(2) Round N
(3) Round CH
51. Section 1051.805 is amended by adding the abbreviations CH
CH
N
52. The authority citation for part 1054 continues to read as follows:
42 U.S.C. 7401–7671q.
53. Section 1054.205 is amended by revising paragraph (p) to read as follows:
(p) Report test results as follows:
(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year, report measured CO
54. Section 1054.235 is amended by adding paragraph (g) to read as follows:
(g) Measure CO
(1) Round CO
(2) Round N
(3) Round CH
55. A new part 1064 is added to subchapter U of chapter I to read as follows:
42 U.S.C. 7401–7671q.
(a) This part describes procedures that apply to testing we require for 2011 and later model year light-duty vehicles, light-duty trucks, and medium-duty personal vehicles (see 40 CFR part 86).
(b) See 40 CFR part 86 for measurement procedures related to exhaust and evaporative emissions.
Determine a refrigerant leakage rate from vehicle-based air conditioning units as described in this section.
(a)
(b)
(c)
(d)
(e)
(f)
56. The authority citation for part 1065 continues to read as follows:
42 U.S.C. 7401–7671q.
57. A new § 1065.257 is added to subpart C to read as follows:
(a)
(b)
(c)
58. A new § 1065.357 is added to subpart D to read as follows:
(a)
(b)
(c)
(d)
(1) Start, operate, zero, and span the N
(2) Introduce a CO span to the analyzer.
(3) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the transfer line and to account for analyzer response.
(4) While the analyzer measures the sample's concentration, record its output for 30 seconds. Calculate the arithmetic mean of this data.
(5) Scale the CO interference by multiplying this mean value (from paragraph (d)(7) of this section) by the ratio of expected CO to span gas CO concentration. In other words, estimate the flow-weighted mean dry concentration of CO expected during testing, and then divide this value by the concentration of CO in the span gas used for this verification. Then multiply this ratio by the mean value recorded during this verification (from paragraph (d)(7) of this section).
(6) Repeat the steps in paragraphs (d)(2) through (5) of this section, but with a CO
(7) Add together the CO and CO
(8) The analyzer meets the interference verification if the result of paragraph (d)(7) of this section is within ±2 percent of the flow-weighted mean concentration of N
(e)
(1) You may omit this verification if you can show by engineering analysis that for your N
(2) You may use a N
59. Section 1065.750 is amended by revising paragraph (a)(1)(ii) and adding paragraph (a)(3)(xi) to read as follows:
(a) * * *
(1) * * *
(ii) Contamination as specified in the following table:
(3) * * *
(xi) N
60. Section 1065.1001 is amended by revising the definition for “Oxides of nitrogen” to read as follows:
61. Section 1065.1005 is amended by adding items to the table in paragraph (b) in alphanumeric order to read as follows:
(b) * * *