After further review of the data available through EIA, the stakeholder comments described earlier in this section, and the reporting requirements in subpart W and subpart NN, the EPA is proposing to eliminate duplicative elements from subpart W for facilities that report to subpart NN, consistent with section II.B.3 of this preamble. The EPA is proposing to amend the reporting requirements in 40 CFR 98.236(aa)(3) for Onshore Natural Gas Processing plants that fractionate NGLs (approximately 100 of the 450 subpart W natural gas processing plants) and also report as a supplier under subpart NN. For this subset of facilities, the EPA reviewed the data from subpart W and subpart NN and determined that there are no gas processing plants that report as fractionators under subpart W that do not also report under subpart NN without supplying a valid explanation. During this review, the EPA found that some of the data elements included in subpart W overlap with data elements in subpart NN. Specifically, the data elements in 40 CFR 98.236(aa)(3)(i), (iii) and (iv) of subpart W overlap with data elements in subpart NN as specified in 40 CFR 98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii), respectively.
To eliminate reporting redundancies, the EPA is proposing several amendments to 40 CFR 98.236(aa)(3). First, to clarify which facilities have data overlap between subparts W and NN, the EPA is proposing to add a reporting element for natural gas processing plants at 40 CFR 98.236(aa)(3)(viii) to indicate whether they report as a supplier under subpart NN. Next, the EPA is proposing that facilities that indicate that they both fractionate NGLs and report as a supplier under subpart NN would no longer be required to report the quantities of natural gas received or NGLs received or leaving the gas processing plant as specified in 40 CFR 98.236(aa)(3)(i), (iii) and (iv). These facilities would, however, be required to continue reporting the data elements specified in 40 CFR 98.236(aa)(3)(ii) and (v) through (viii), as these reporting elements do not overlap with subpart NN reporting elements. Natural gas processing plants that do not fractionate or that fractionate but do not report as a supplier under subpart NN would continue to report all of the reporting elements for natural gas processing plants as specified in 40 CFR 98.236(aa)(3).
The EPA is also proposing to remove the reporting elements for throughput for LDCs in 40 CFR 98.236(aa)(9). The EPA reviewed the data from subpart W and subpart NN and determined that there are no LDCs that report under subpart W that do not also report under subpart NN. In fact, an average of 385 LDCs report under subpart NN, while 170 LDCs report under subpart W. Subpart NN therefore provides more comprehensive coverage of the Natural Gas Distribution industry segment. Additionally, subpart NN has been in effect for LDCs since RY2011 while subpart W throughput information has only been collected since RY2015; thus, subpart NN has a more robust historical data set. During this review, the EPA determined that the data elements found in 40 CFR 98.236(aa)(9)(i) through (v) of subpart W overlap with data elements in subpart NN as specified in 40 CFR 98.406(b)(1) through (3), 98.406(b)(5) and (6), and 98.406(b)(13). To eliminate reporting redundancies, the EPA is proposing to remove these reporting elements from subpart W.
The EPA is also proposing to remove the reporting elements for the volume of natural gas used for operational purposes and natural gas stolen specified in 40 CFR 98.236(aa)(9)(vi) and (vii). These reporting elements are unique to subpart W and have caused confusion for subpart W reporters, require additional burden to estimate, and have not been used for the EPA's analyses of the subpart W data. As a result of removing these data elements, the EPA proposes to reserve paragraph 40 CFR 98.236(aa)(9). Table 2 of this preamble shows all the duplicative data elements that the EPA is proposing to remove from subpart W for facilities that also report to subpart NN.
Table 2. List of Proposed Subpart W Data Elements to be Removed where Analogous Subpart NN Data Elements are Reported
Subpart W Data Elements Proposed to be Eliminated
Analogous Subpart NN Data Elements
Citation
Description
Citation
Description
Local Distribution Companies
§98.236(aa)(9)(i)
Quantity of natural gas received at all custody transfer stations
§98.406(b)(1)
§98.406(b)(5)
Annual volume of natural gas received by the LDC at its city gate stations and Annual volume natural gas that bypassed the city gate(s)
§98.236(aa)(9)(ii)
Quantity of natural gas withdrawn from in-system storage
§98.406(b)(3)
Annual volume natural gas withdrawn from on-system storage and annual volume of vaporized LNG withdrawn from storage
§98.236(aa)(9)(iii)
Quantity of natural gas added to in-system storage
§98.406(b)(2)
Annual volume of natural gas placed into storage or liquefied and stored
§98.236(aa)(9)(iv)
Quantity of natural gas delivered to end users
§98.406(b)(13)(i) through (iv)
Annual volume of natural gas delivered by the LDC to residential consumers, commercial consumers, industrial consumers, electricity generating facilities
§98.236(aa)(9)(v)
Quantity of natural gas transferred to third parties
§98.406(b)(6)
Annual volume of natural gas delivered to downstream gas transmission pipelines and other local distribution companies
Natural Gas Processing Plants that Fractionate NGLs
§98.236(aa)(3)(i)
Quantity of natural gas received
§98.406(a)(3)
Annual volume of natural gas received for processing
§98.236(aa)(3)(iii)
Cumulative quantity of all NGLs (bulk and fractionated) received
§98.406(a)(2)
§98.406(a)(4)(i)
Annual quantity of each NGL product received and annual quantities of y-grade, o-grade and other bulk NGLs received
§98.236(aa)(3)(iv)
Cumulative quantity of all NGLs (bulk and fractionated) leaving
§98.406(a)(1)
§98.406(a)(4)(ii)
Annual quantity of each NGL product supplied and annual quantities of y-grade, o-grade and other bulk NGLs supplied

h. Onshore Natural Gas Processing Industry Segment
According to 40 CFR 98.230(a)(3), the Onshore Natural Gas Processing industry segment currently includes all facilities that fractionate NGLs. The industry segment also includes all facilities that separate NGLs from natural gas or remove sulfur and CO2 from natural gas, provided the annual average throughput at the facility is 25 MMscf per day or greater. The industry segment also includes all residue gas compression equipment owned or operated by natural gas processing facilities that is not located within the facility boundaries.
GPA Midstream has expressed concern that the current definition of the Onshore Natural Gas Processing industry segment applies to some compressor stations simply because they have an amine unit that is used to remove sulfur and CO2 from natural gas. According to GPA Midstream, it would be more appropriate for such facilities to be in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. GPA Midstream also explained that the 25 MMscf per day threshold creates additional burden and uncertainty for these compressor station facilities because they do not know until the end of the year whether they will be above or below the threshold. Thus, they need to collect the applicable data for both the Onshore Natural Gas Processing industry segment and the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment so that they will have the required data for whichever industry segment ultimately applies to them. To resolve this issue and to promote consistency among regulatory programs, GPA Midstream recommended replacing the onshore natural gas processing definition in subpart W with the natural gas processing plant definition in NSPS OOOOa.
After review of these comments, we are proposing to replace the definition of "Onshore natural gas processing" in 40 CFR 98.230(a) with language similar to the definition of "natural gas processing plant" in NSPS OOOOa. NSPS OOOOa defines "natural gas processing plant (gas plant)" as any processing site engaged in the extraction of NGLs from field gas, fractionation of mixed NGLs to natural gas products, or both. The definition specifies that a Joule-Thompson valve, a dew point depression valve, or an isolated or standalone Joule-Thompson skid is not a natural gas processing plant. There are two minor editorial differences between the proposed definition in 40 CFR 98.230(a) and the definition in NSPS OOOOa. First, instead of defining a natural gas processing "plant," as in the definition in NSPS OOOOa, we are proposing to describe what is meant by "natural gas processing" so that the structure of 40 CFR 98.230(a)(3) is consistent with the structure of all of the other industry segment definitions in 40 CFR 98.230(a). Second, the definition in NSPS OOOOa refers to "extraction" of NGLs from natural gas, but this term is not defined. Thus, we are proposing to retain the term "forced extraction" in the current provisions of 40 CFR 98.230(a)(3) and revise the definition of this term slightly in 40 CFR 98.238. The current definition of "forced extraction" specifies that forced extraction does not include "portable dewpoint suppression skids." We are proposing to revise the definition to indicate instead that forced extraction does not include "a Joule-Thomson valve, a dewpoint depression valve, or an isolated or standalone Joule-Thomson skid." These changes would make the definition of "forced extraction" in subpart W consistent with the language in the definition of a natural gas processing plant in NSPS OOOOa. This proposed amendment would provide reporters with certainty about the applicable industry segment for the reporting year, reducing the monitoring data they must collect to only the information needed for the applicable industry segment, consistent with section II.B.2 of this preamble.
This proposed amendment is not expected to decrease overall coverage of the GHGRP for the petroleum and natural gas systems industry, although we anticipate that some facilities would report under a different industry segment going forward. Based on reported data for RY2020, about 19 percent of facilities reporting in the Onshore Natural Gas Processing industry segment do not fractionate NGLs and report zero NGLs received and leaving the facility. These facilities meet the current definition of natural gas processing because they are separating CO2 and/or hydrogen sulfide. These facilities would not meet the proposed revised definition for natural gas processing and instead, their emissions would be reported as part of either existing or new onshore petroleum and natural gas gathering and boosting facilities. In most cases, we anticipate that operations at a former gas processing facility would be incorporated into an existing gathering and boosting facility that has been subject to reporting, and the total emissions from the expanded gathering and boosting facility would be similar to the emissions that would have been reported by the separate facilities under the existing industry segment definitions. In cases where a former gas processing facility is located in a basin where the owner or operator does not have an existing reporting gathering and boosting facility, we expect that a new gathering and boosting facility including the former gas processing facility would be created because the emissions from the former gas processing facility alone would exceed the reporting threshold of 25,000 mtCO2e. If the same owner or operator has other gathering and boosting operations in the same basin that have emissions less than 25,000 mtCO2e, then the new gathering and boosting facility could result in increased coverage of the industry segment and greater total reported emissions than would be reported under the current industry segment definitions.
The proposed revised definition for natural gas processing also does not include the 25 MMscf per day threshold for facilities that do not fractionate NGLs. Under the current definition of onshore natural gas processing, processing plants that do not fractionate gas liquids and generally operate close to the 25 MMscf per day threshold do not know until the end of the year whether they will be above or below the threshold, so they must be prepared to report under whichever industry segment is ultimately applicable. The two potentially applicable segments report emissions from different sources and with different calculation methods. For example, facilities in the Onshore Natural Gas Processing industry segment are not required to report emissions from atmospheric storage tanks and are required to measure leaks from individual compressors, while facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment are required to report emissions from atmospheric storage tanks but may use emission factors to calculate emissions from compressors rather than conducting measurements. These sites would meet the revised proposed definition of natural gas processing regardless of their throughput level, so they would have the certainty of knowing they would be subject to reporting as natural gas processing facilities every year, and as a result, removing the 25 MMscf per day threshold is expected to increase the number of facilities that report under the Onshore Natural Gas Processing industry segment. We request comment on the impact the proposed change would have on the number of reporting facilities and emissions from both the Onshore Natural Gas Processing and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. We also request comment on any other advantages or disadvantages to finalizing the proposed change.
Finally, we note that the definition of natural gas processing plant in NSPS OOOOa does not specifically include residue gas compression equipment. Residue gas compression is defined in 40 CFR 98.238 as the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline. Per 40 CFR 98.230(a)(3), the Onshore Natural Gas Processing industry segment includes all residue gas compression equipment owned or operated by the natural gas processing plant. We are requesting comment on whether to remove the existing requirement to include residue gas compression equipment owned or operated by the natural gas processing facility from 40 CFR 98.230(a)(3) and 40 CFR 98.231(b). If this change were finalized, we anticipate that residue gas compression equipment would then be part of the Onshore Natural Gas Transmission Compression industry segment, which would require reporters with residue gas compression equipment that currently only report under the Onshore Natural Gas Processing industry segment to begin reporting under both the Onshore Natural Gas Processing and Onshore Natural Gas Transmission Compression industry segments in order to fully report their facility emissions. As part of the request for comment on this issue, we request comment on the expected impact on the level of reported emissions that would result if this change were finalized. We also request comment on other rationale for or against finalizing this change.
3. Other Proposed Minor Revisions or Clarifications
See Table 3 of this preamble for the miscellaneous minor technical corrections not previously described in this preamble that we are proposing throughout subpart W, consistent with section II.A.5 of this preamble.
Table 3. Proposed Technical Corrections to Subpart W
Section (40 CFR)
Description of Proposed Amendment
98.232(b), 98.233(s), 98.236(s)
Update the outdated acronym "BOEMRE" to the current acronym "BOEM."
98.232(b), 98.233(s)
Update the cross references to the BOEM requirements from "30 CFR 250.302 through 304" to "30 CFR 550.302 through 304."
98.233(a)(1)
Revise the definition of the equation variable "EFt" to consolidate the list of applicable industry segments and tables into one sentence.
98.233(e)(1)(x)
Add "at the absorber inlet" to the end of the paragraph to clarify the location for the wet natural gas temperature and pressure to be used for modeling.
98.233(g)(4)(ii)
Revise the instance of "formation on N2O" in the second sentence to read "formation of N2O" to correct a typographical error.
98.233(j), 98.236(j)
Revise the instances of "oil," "oil/condensate," and "liquid" to read "hydrocarbon liquids" for consistency with the requirement in 40 CFR 98.233(j) to calculate emissions from "atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids," as noted in the 2015 amendments to subpart W (80 FR 64272, October 22, 2015).
98.233(n)(5)
Correct the cross reference in the definition of the equation variable "Yj" from paragraph (n)(1) to (n)(2).
98.233(o) introductory text and (p) introductory text
Moved the last sentence in each paragraph to be the second sentence to clarify that the calculation methodology for compressors routed to flares, combustion, and vapor recovery apply to all industry segments.
98.233(p)(1)(i)
Correct the internal cross reference from paragraph (o) to paragraph (p).
98.233(p)(4)(ii)(C)
Add missing "in" to read "according to methods set forth in § 98.234(d)."
98.233(r) introductory text
Revise the instance of "CH" in the third sentence to read "CH4" to correct a typographical error.
98.233(r), Equations W-32A and W-32B
Correct the cross reference in the definition of the equation variable "Es,MR,i" and the equation variable "CountMR" from paragraph (q)(9) to (q)(2)(xi).
98.233(r)(6)(ii)
Add reference to components listed in 40 CFR 98.232(i)(3), for consistency with proposed amendments to 40 CFR 98.233(r)(6)(i).
98.233(t)(2)
Revise the definition of equation variable "Za" to include the sentence following the definition of that variable to correct a typographical error.
98.233(u)(ii)
Format the heading to be in italicized text.
98.233(z)
Revise the instances of "high heat value" to read "higher heating value" to correct inconsistency in the term.
98.233(z), Equations W-39A and W-39B
Remove unnecessary "constituent" from "CO2 constituent" and "methane constituent" and remove "gas" from "gas hydrocarbon constituent." Add missing "the" to read "to the combustion unit" in several variable definitions.
98.236 introductory text
Add missing "than" to read "report gas volumes at standard conditions rather than the gas volumes at actual conditions"
98.236(e)(2)
Revise the instances of "vented to" a control device, vapor recovery, or a flare to read "routed to" to correct inconsistency in the phrases "vented to" and "routed to."
Revise the instances of "vapor recovery device" to read "vapor recovery system" to correct inconsistency in the term.
98.236(j)(2)
Clarify that the reported information in paragraphs (j)(1)(i) through (xvi) should only include those atmospheric storage tanks with emissions calculated using Calculation Method 3.
98.236(l)(1), (2), (3), and (4) introductory text
Revise the instances of "vented to a flare" to read "routed to a flare" to correct inconsistency in the phrases "vented to" and "routed to."
98.236(p)(3)(ii)
Add a missing period at the end of the sentence.
98.236(bb)
Clarify that reporting for missing data procedures includes the procedures used to substitute an unavailable value of a parameter (per 40 CFR 98.235(h)).
98.236(cc)
Correct the cross references from paragraph (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), and (l)(4)(iii) to (l)(1)(v), (l)(2)(v), (l)(3)(iv), and (l)(4)(iv), respectively.
98.238
Remove the second definition of "Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements" to eliminate an inadvertent identical duplicative definition.
Table W-1A, Table W-3B, and Table W-4B to Subpart W of Part 98
Change "Low Continuous Bleed Pneumatic Device Vents" to "Continuous Low Bleed Pneumatic Device Vents" and change "High Continuous Bleed Pneumatic Device Vents" to "Continuous High Bleed Pneumatic Device Vents" to be consistent with the terms used throughout the rest of subpart W.
Table W-3B and Table W-4B to Subpart W of Part 98
Change table headings and footnotes to clarify that the population emission factors for pneumatic device vents are whole gas emission factors rather than total hydrocarbon emission factors.

4. Best Available Monitoring Methods
The EPA is proposing that facilities would be allowed to use BAMM on a short-term transitional basis for the proposed amendments for the 2023 reporting year for only the specific industry segments and emission sources for which new monitoring or data collection requirements are being proposed. These industry segments and emission sources include calculating and reporting emissions from natural gas pneumatic devices at onshore natural gas processing facilities, natural gas intermittent bleed pneumatic devices for which the reporter conducts routine monitoring surveys, acid gas removal vents at LNG import/export facilities, other large release events at all facilities, miscellaneous flared sources, glycol dehydrators and atmospheric storage tanks routed to vapor recovery systems, compressor sources and mode-source combinations for which new measurements would be required, and measurements taken using a high volume sampler. We are also proposing that reporters of an onshore natural gas processing facility that becomes part of an onshore petroleum and natural gas gathering and boosting facility, or vice versa, solely due to the proposed change in the definition of 40 CFR 98.230(a)(3) would be allowed to use BAMM for the emission sources for which measurements were not required under the previous industry segment. This proposal would allow reporters to use best available methods to estimate inputs to emission equations for the newly proposed emission sources using their best engineering judgment for cases where the monitoring of these inputs would not be possible beginning on January 1, 2023.
These reporters would have the option of using BAMM from January 1, 2023, to December 31, 2023, without seeking prior EPA approval for certain parameters that cannot reasonably be measured according to the monitoring and quality assurance/quality control (QA/QC) requirements of 40 CFR 98.234. This additional time for reporters to comply with the monitoring methods for new emission sources in subpart W would allow facilities to install the necessary monitoring equipment during other planned (or unplanned) process unit downtime, thus avoiding process interruptions. The EPA is not proposing to allow the use of BAMM beyond RY2023 and does not anticipate that BAMM would be needed beyond 2023 for the specific industry segments and emissions sources with proposed amendments in this rule. The EPA is also not proposing to allow the use of BAMM for industry segments and emission sources for which no amendments have been proposed that would require additional data collection because reporters should already be collecting the measurements and activity data needed to meet the requirements of the current rule.
K. Subpart X  --  Petrochemical Production
We are proposing several amendments to subpart X of Part 98 (Petrochemical Production) to improve the quality of data reported and to clarify the calculation, recordkeeping, and reporting requirements for the reasons described in this section and in section II.A of this preamble.
For the reasons described in section II.A.3 of this preamble, we are proposing to add a reporting element in 40 CFR 98.246(b)(7) and (c)(3) for each flare that is reported under the CEMS and optional ethylene combustion methodologies. These sections of subpart X currently require reporting of the total emissions from each flare that burns off-gas from a petrochemical process unit for which emissions are determined under the CEMS or optional ethylene combustion methodologies. We are proposing that reporters also report estimated fractions of the total CO2, CH4, and N2O emissions from these flares that are due to combusting petrochemical off-gas because the current requirements result in an overestimate of emissions attributed to a petrochemical process unit when the flare is not dedicated to a petrochemical process unit, particularly if the flare is also used to combust off-gas from non-petrochemical process units. The proposed requirement would allow the fractions attributed to each petrochemical process unit that routes emissions to the flare to be estimated using engineering judgment. This proposed change would allow more accurate quantification of emissions both from individual petrochemical process units and from the industry sector as a whole.
For the reasons described in section II.A.4 of this preamble, we are proposing to add a requirement in 40 CFR 98.246(c)(6) to report the names and annual quantity (in metric tons) of each product produced in each ethylene production process under the optional ethylene combustion methodology. Subpart X currently requires reporting of only the quantity of ethylene produced. The proposed change would make product reporting under the optional ethylene combustion methodology consistent with product reporting requirements under the CEMS and mass balance reporting options. Data on the quantities of all products will improve the EPA's ability to verify reported emissions from these process units, and the data will be useful in informing future policy decisions.
For the reasons described in section II.A.5 of this preamble, we are proposing two changes to clarify emissions calculation requirements for flares. Currently, 40 CFR 98.243(b)(3) and (d)(5) cross-reference the calculation procedures in 40 CFR 98.253(b)(1) through (b)(3) of subpart Y. We are proposing to revise these sections to cross-reference all of 40 CFR 98.253(b) to clarify that the provisions added in past amendments and in this amendments package to the introductory paragraph in 40 CFR 98.253(b) also apply to flares that are subject to reporting under subpart X. This proposed change would clarify that subpart X reporters are not required to report emissions from combustion of pilot gas and, as discussed in section III.L of this preamble, that gas released during SSM events of <500,000 scf/day are excluded from Equation Y-3.
Additionally, we are proposing five amendments to clarify subpart X rule language pertaining to reporting of required data elements. In previous rule amendments, we added requirements to report the annual quantity of each petrochemical product produced from each process unit. In making the changes, we inadvertently introduced some overlapping reporting requirements. First, to clarify the reporting requirements and eliminate confusion for facilities that use the mass balance approach, we are proposing to amend 40 CFR 98.246(a)(2) to remove the requirement to report feedstock and product names. The rule currently specifies in two places that a reporter using the mass balance methodology must report the feedstock and product names for a subject process unit. The requirement in 40 CFR 98.246(a)(2) is to report the "names of products, and names of carbon-containing feedstocks." The requirement in 40 CFR 98.246(a)(12) is to report the "(n)ame (...) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of §98.243." The requirement in 40 CFR 98.246(a)(13) is to report the "(n)ame (...) of each product included in Equations X-1, X-2, and X-3." Although the language in 40 CFR 98.246(a)(2) is slightly different from the language in 40 CFR 98.246(a)(12) and (13), the scope of 40 CFR 98.246(a)(2) is identical to the collective scope of 40 CFR 98.246(a)(12) and (13). For example, all gaseous carbon-containing feedstocks must be entered in the Equation X-1 calculation, all liquid carbon-containing feedstocks must be entered in the Equation X-2 calculation, and all solid carbon-containing feedstocks must be entered in the Equation X-3 calculation. Thus, the current requirement in 40 CFR 98.246(a)(12) to report the name of each carbon-containing feedstock used in any of the equations means all carbon-containing feedstocks must be reported, which is identical to the requirement in 40 CFR 98.246(a)(2) to report the names of carbon-containing feedstocks. A similar analysis applied to the products results in the conclusion that the current requirement in 40 CFR 98.246(a)(13) to report the name of each product used in any of the equations means all products must be reported, which is identical to the requirement in 40 CFR 98.246(a)(2) to report the names of products. Note that the rule does not specify reporting of "carbon-containing" products; this is unnecessary because the term "product" is defined in 40 CFR 98.248 to mean "...carbon-containing outputs..." To eliminate the redundancy, we are proposing to delete the requirement to report names of products and the names of carbon-containing feedstocks from 40 CFR 98.246(a)(2) because the same requirements are also included in 40 CFR 98.246(a)(12) for feedstocks and 40 CFR 98.246(a)(13) for products.
The second amendment to the mass balance reporting requirements is to revise 40 CFR 98.246(a)(5) and 40 CFR 98.246(a)(13) to clarify the petrochemical and product reporting requirements for integrated ethylene dichloride/vinyl chloride monomer (EDC/VCM) process units. In a letter received from Occidental Chemical Company titled "Request to Consider IPCC Balanced EDC/VCM Process Studies and Data for the Elimination of e-GGRT Validation Messages at VCM Production Facilities Reporting Under Subpart X," dated July 10, 2015 (available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424), industry representatives indicated that an integrated EDC/VCM process unit is a continuous process in which the EDC is produced as an intermediate that is used in the production of VCM; purified EDC circulates to the VCM production portion of the process, and multiple recovery loops recycle unconverted EDC from the VCM operations to the EDC operations for purification. These streams that pass back and forth between the EDC and VCM portions of the integrated unit are not isolated and are not measured in a manner that would allow for accurate calculation of the amount of intermediate EDC produced. Since the amount of EDC produced as an intermediate in such process units may not be measured, subpart X was previously amended to allow reporters to consider the entire integrated EDC/VCM process unit to be the petrochemical process unit (proposal at 81 FR 2536, January 15, 2016; final at 81 FR 89188, December 16, 2016). At the same time, 40 CFR 98.246(a)(5) was amended to specify that the amount of intermediate EDC produced in such units and included in the total reported amount of EDC petrochemical produced could be based on either measurements or an estimate. In subsequent years, data reported under subpart X of the GHGRP indicated that some facilities with an integrated EDC/VCM process unit withdraw small amounts of the EDC as a separate product stream. The amendments in 2016 were silent on how to report the amount of any EDC that is withdrawn as a separate product from the integrated unit. The intent of the proposed changes is that the amount of EDC product not used as an intermediate would continue to be determined as it would be for a standalone EDC process unit, this amount of EDC product would be added to the amount of intermediate EDC, and the total would be reported under 40 CFR 98.246(a)(5) as the amount of EDC petrochemical produced by the integrated EDC/VCM process unit. To clarify this intent we are proposing to revise 40 CFR 98.246(a)(5) to specify that the portion of the total amount of EDC produced that is an intermediate in the production of VCM may be either a measured quantity or an estimate, the amount of EDC withdrawn from the process unit as a separate product (i.e., the portion of EDC produced that is not utilized in the VCM production) is to be measured in accordance with 40 CFR 98.243(b)(2) or (3), and the sum of the two values is to be reported under 40 CFR 98.246(a)(5) as the total quantity of EDC petrochemical from an integrated EDC/VCM process unit. We are also proposing a harmonizing change in 40 CFR 98.246(a)(13) to clarify that the amount of EDC product to report from an integrated EDC/VCM process unit should be only the amount of EDC, if any, that is withdrawn from the integrated process unit and not used in the VCM production portion of the integrated process unit. Reporting as a product only the quantity of EDC not used in the VCM process is consistent with the boundary of the mass balance being around the integrated EDC/VCM process unit.
For facilities that use CEMS, we are proposing a third amendment to 40 CFR 98.246(b)(8) to clarify the reporting requirements for the amount of EDC petrochemical when using an integrated EDC/VCM process unit. In previous amendments (81 FR 89188, December 16, 2016), reporting requirements related to the quantity of intermediate EDC for an integrated EDC/VCM process unit were added to the petrochemical quantity reporting requirements at 40 CFR 98.246(b)(8) for CEMS-monitored units that were identical to the reporting requirements added to 40 CFR 98.246(a)(5) that are discussed above for mass balance units. This 2016 language was added so that the reporting requirements would be the same under both the mass balance methodology and the CEMS methodology. However, an EDC manufacturer does not need to consider an integrated EDC/VCM process unit to be the petrochemical process unit when using CEMS since vent streams are directly monitored and thus recycle streams from the VCM to EDC process are not required to be quantified as with a mass balance unit. Under the mass balance option, the amount of product must be a measured value because the quantity is used in the emissions calculation equation; thus, we allowed the entire integrated unit to be considered the petrochemical process unit so the amount of VCM product could be the primary reported product, and it would be measured. Under the CEMS option, the product quantity is used only in data verification procedures and other data analyses, and the EPA has tentatively determined that, for these purposes, reporting an estimated value is an acceptable alternative to incurring the expense of modifying an integrated unit process unit so that measurements can be taken. Thus, we are proposing to revise 40 CFR 98.246(b)(8) by removing language related to considering the petrochemical process unit to be the entire integrated EDC/VCM process unit.
For facilities that use the optional ethylene combustion methodology to determine emissions from ethylene production process units, we are proposing a fourth amendment to 40 CFR 98.246(c)(4) to clarify that the names and annual quantities of feedstocks that must be reported would be limited to feedstocks that contain carbon. This proposed change will make the feedstock reporting requirement under the optional ethylene combustion methodology consistent with the feedstock reporting requirements under the mass balance and CEMS options.
The fifth proposed change to clarify the reporting requirements under subpart X consists of clarifying changes to 40 CFR 98.246(a)(15). Currently, this paragraph specifies that the annual average molecular weight must be reported for each gaseous feedstock and product. The proposed revision would more clearly specify that molecular weight must be reported for gaseous feedstocks and products only when the quantity of the gaseous feedstock or product used in Equation X-1 is in standard cubic feet; the molecular weight does not need to be reported when the quantity of the gaseous feedstock or product is in kilograms. This change would be consistent with statements in the definitions of the terms for volume or mass in Equation X-1. We are also proposing to rearrange the text in 40 CFR 98.246(a)(15) and split the paragraph into two sentences to improve clarity.
These proposed clarifying changes would pose no new monitoring, reporting, or recordkeeping requirements. We are also proposing related confidentiality determinations for the new or revised data elements, as discussed in section VI of this preamble.
L. Subpart Y  --  Petroleum Refineries
1. Proposed Revisions to Improve the Quality of Data Collected for Subpart Y
We are proposing several amendments to subpart Y of Part 98 (Petroleum Refineries) to improve data collection, clarify rule requirements, and correct an error in the rule.
For the reasons described in section II.A.2 and II.A.4 of this preamble, we are proposing to amend some of the requirements for DCUs to improve data collection and our ability to perform verification of reported data for these emission sources. During the verification of DCU emissions, we noted a disproportionate number of facilities were messaged with potential emission errors that used mass measurements from company records to estimate the dry coke at the end of the coking cycle (as an alternative to estimating this quantity using Eq. Y-18a) in 40 CFR 98.257(b)(41). Through correspondence with facilities regarding these potential emission errors, we found that the some of the errors were due to reporters incorrectly determining the mass of coke at the end of the coking cycle on a wet basis rather than on a dry basis. This led to an erroneously high value being used for the Mcoke input parameters to Equation Y-18b, resulting in an unusually low value of Mwater and subsequently lower-than-expected methane emissions. We also found that some of the errors were explained by the use of a facility-specific bulk density of coke that was sufficiently different from the default value used in EPA-estimated emissions to generate a potential error message. Finally, we found that some facilities indicated the coke may not be completely submerged by water due to initiating draining prior to atmospheric venting. Such activities undermine some of the underlying assumptions of the steam generation model being used to estimate DCU emissions. In order to improve the quality of data collected and our ability to ensure the reported data are accurate, we are proposing two amendments to the DCU provisions.
The first proposed amendment is designed to enhance the reporting and recordkeeping specifically for facilities using mass measurements from company records to estimate Mcoke. Currently, facilities using mass measurements have less recordkeeping requirements than those facilities using Equation Y-18a to estimate the quantity. Facilities using Equation Y-18a are required to keep records of the drum outage, drum height, and the drum diameter as specified in 40 CFR 98.257(b)(42) through (44), while facilities using mass measurements from company records for Mcoke do not have any related reporting or recordkeeping other than the recordkeeping requirement of the Mcoke quantity in 40 CFR 98.257(b)(41). Therefore, we have limited data available by which to verify the reported dry mass of coke at the end of the cycle, Mcoke. In order to perform more robust and consistent verification of all of these reported quantities in future years, we are proposing to add reporting requirements for facilities using mass measurements from company records to estimate the amount of dry coke at the end of the coking cycle in 40 CFR 98.256(k)(6)(i) and (ii). These new subparagraphs would require these facilities to additionally report, for each DCU: (1) the internal height of the DCU vessel; and (2) the typical distance from the top of the DCU vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet). These new elements will allow the EPA to estimate and verify the reported mass of dry coke at the end of the cooling cycle as well as the reported DCU emissions, ensuring the most consistent and accurate data are provided. We do not anticipate that the proposed data elements would require any additional monitoring or data collection by reporters, as these data are likely already available in existing company records. We are proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
The second amendment for DCUs we are proposing is to amend Equation Y-18b in 40 CFR 98.253(i)(2) to include a new variable "fcoke" and revise the existing descriptions of the "Mwater" output and "Hwater" variable. As noted in the discussion, some of the facilities messaged for potential emission errors explained that the coke was not completely submerged at the time the vessel is vented to the atmosphere, which contradicts assumptions underlying the calculation methodology. First, we are proposing to revise the definitions of "Mwater" and "Hwater" to add the phase "or draining" to specify that these parameters reflect the mass of water and the height of water, respectively, at the end of the cooling cycle just prior to atmospheric venting or draining. The steam generation model requires a complete accounting of the heat within the unit prior to venting or draining since steam generation will occur if superheated water is drained from the unit prior to venting. We are also proposing similar revisions to the recordkeeping requirements at 40 CFR 98.257(b)(45) and (46) to add the phrase "or draining" to the description of the records. We are also proposing to add a new variable "fcoke" to Equation Y-18b to allow facilities that do not completely cover the coke bed with water prior to venting or draining to accurately estimate the mass of water in the drum. The "fcoke" variable would be defined as the fraction of coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining, where a value of 1 represents cases where the coke is completely submerged in water. The second term in Equation Y-18b represents the volume of coke in the drum. It is subtracted from the water-filled coke bed volume to determine the volume of water. If the coke bed is not completely submerged in the water, subtracting the entire volume of coke from the water-filled coke bed volume will underestimate the actual volume of water in the coke drum vessel, resulting in an underestimate of the methane emissions. Adding the "fcoke" variable to the second term in Equation Y-18b would make the equation universally applicable in cases where the coke bed is not fully submerged when the coke drum is first vented or drained. We are also proposing to add a corresponding recordkeeping requirement at 40 CFR 98.257(b)(53).
We are proposing several clarifying changes, for the reasons described in section II.A.5 of this preamble. We are proposing to add clarifying language to 40 CFR 98.253(c) and 98.253(e) to reiterate the language from 40 CFR 98.252(b) that the emissions being quantified in these paragraphs are coke burn-off emissions rather than emissions that may occur from other venting events. The language at 40 CFR 98.252(b) clearly indicates that the emissions to be reported are "... coke burn-off emissions from each catalytic cracking unit, fluid coking unit, and catalytic reforming unit..." [emphasis added]. However, the language at to 40 CFR 98.253(c) and 98.253(e) could be construed to apply to other vented emissions. We have received a GHGRP Help Desk question concerning the applicability of the calculation methodology to other venting events. To help clarify that the calculation methodologies in 40 CFR 98.253(c) and 98.253(e) are specific to coke burn-off emissions, we are proposing to add "from coke burn-off" immediately after the first occurrence of "emissions" in the introductory text of 40 CFR 98.253(c) and 40 CFR 98.253(e).
We are proposing a clarifying change to correct an inconsistency introduced into subpart Y by the amendments published on December 9, 2016 (81 FR 89188). The introduction to the flare emission calculation requirements at 40 CFR 98.253(b) was revised in 2016 to state that all gas discharged through the flare stack must be included in the calculations except for pilot gas. The intent of this provision was to require inclusion of purge and sweep gas in addition to SSM events. However, because Equation Y-3 excludes SSM events less than 500,000 scf/day, the new provision created an apparent inconsistency about whether to include or exclude SSM events less than 500,000 scf/day in Equation Y-3. Some reporters have interpreted that such SSM events must be included. We are proposing to clarify in 40 CFR 98.253(b) that SSM events less than 500,000 scf/day may be excluded, but only if reporters are using the calculation method in 40 CFR 98.253(b)(1)(iii). This proposed clarification corrects the 2016 amendment, which was not intended to eliminate the exclusion when reporters use Equation Y-3, and would reduce repeated verification and correction of errors submitted in reports.
We are proposing a correction to an erroneous cross-reference in 40 CFR 98.253(i)(5) for the reasons described in this section and section II.A.5 of this preamble. The section inaccurately defines the term Mstream in Equation Y-18f for DCUs. Currently, Mstream is defined as, "Mass of steam generated and released per decoking cycle (metric tons/cycle) as determined in paragraph (i)(3) of this section." The correct cross-reference is paragraph (i)(4) instead of (i)(3). The proposed change would not have any impact on burden.
Finally, we are proposing a change to correct an inconsistency introduced into subpart Y by the amendments published on December 9, 2016 (81 FR 89188). The DCU emission calculations were updated in 2016, and, as part of that update, 40 CFR 98.253(j) was revised to remove the option to calculate CH4 emissions from DCUs using the process vent method (Equation Y-19). However, the DCU recordkeeping requirements for the process vent method at 40 CFR 98.257(b)(53) through (56) were inadvertently not removed from the rule. We are proposing to revise 40 CFR 98.257(b)(53) to include recordkeeping requirement for the "fcoke" variable, as previously discussed in this section, and to remove and reserve the recordkeeping requirements in paragraphs 98.257(b)(54) through (56) since Equation Y-19, the process vent calculation method, is no longer used to calculate DCU emissions.
2. Proposed Revisions to Streamline and Improve Implementation for Subpart Y
For the reasons described in this section and in section II.B.2 of this preamble, we are proposing to allow the use of mass spectrometer analyzers to determine gas composition and molecular weight without the use of a gas chromatograph. Currently, the methods for determining gas composition in 40 CFR 98.254(d) rely on gas chromatography. Advances in data analytics have made it easier for mass spectrometer analyzers to determine concentrations of individual compounds from a mixture of hydrocarbons without the need for pre-separation of the compounds using gas chromatography. Direct analysis using mass spectrometer analyzers greatly reduces the cycle time between sample analyses, allowing improved process control. As such, some refinery owner/operators use direct mass spectrometer analyzers to determine gas stream composition. The proposed inclusion of direct mass spectrometer analysis as an allowable gas composition method in 40 CFR 98.254(d) would allow these reporters to use the same analyzers used for process control or for compliance with continuous sampling required under the National Emissions Standards for Hazardous Air Pollutants from Petroleum Refineries (40 CFR part 63, subpart CC) to comply with GHGRP requirements in subpart Y. Currently, these reporters have to conduct separate periodic sampling of these gas streams for analysis using gas chromatography to comply with GHGRP requirements in subpart Y. Thus, the proposed inclusion of mass spectrometer analyzers for determining gas composition will reduce the burden for these reporters. It is also expected to provide more accurate data due to the use of continuous analyzers rather than periodic sampling.
M. Subpart BB  --  Silicon Carbide Production
For the reasons described in section II.A.4 of this preamble, we are proposing revisions to the reporting requirements for subpart BB of Part 98 (Silicon Carbide Production) to improve the quality of the data collected under the GHGRP.
The original 2009 GHG Reporting Rule for silicon carbide production required reporting CH4 emissions by measuring petroleum coke consumption and applying a default CH4 emission factor of 10.2 kilograms of CH4 per metric ton of coke consumed (see 74 FR 56260). However, in 2013, we removed the requirement for silicon carbide production facilities to report CH4 emissions from silicon carbide process units or furnaces and the CH4 calculation methodology because we determined that the then-current CH4 calculation methodologies in subpart BB overestimated the emissions of CH4 from silicon carbide facilities. At the time we determined the following: the equations did not take into consideration the destruction of CH4 emissions, the CH4 emissions from these facilities were typically controlled, the CH4 emissions from these facilities were minimal, and the requirement to report CH4 emissions was not necessary to understand the emissions profile of the industry (see 78 FR 19802, April 2, 2013, and 78 FR 71904, November 29, 2013). The determination to not require reporting of CH4 emissions was predicated on the conclusion that because CH4 emissions are typically controlled, CH4 emissions from these facilities are minimal. Although our understanding is still that CH4 emissions are typically controlled, we are proposing to amend the rule in order to gather more information on CH4 control practices at silicon carbide production facilities to better understand the extent of those control practices and their impact on CH4 emissions. Specifically, we are interested in how the CH4 emissions are controlled, the efficiency of the control technologies, and to what extent these technologies are operated throughout the year. As such, we are proposing adding new reporting requirement 40 CFR 98.286(c) such that if CH4 abatement technology is used at silicon carbide production facilities, then facilities must report: (1) the type of CH4 abatement technology used, and the date of installation for each; (2) the CH4 destruction efficiency (percent destruction) for each CH4 abatement technology; and (3) the percentage of annual operating hours that CH4 abatement technology was in use for all silicon carbide process units or production furnaces combined. The proposed reporting requirements would be used to confirm the operation and efficiency of CH4 abatement at silicon carbide facilities and would enable us to determine whether the EPA's 2013 determination that CH4 emissions are typically controlled (and therefore minimal) remains accurate. Although silicon carbide facilities would continue to not be required to estimate CH4 emissions from their processes for their GHGRP annual report, providing data on CH4 abatement technology and usage would allow the EPA to assess the potential for unabated CH4 emissions that may influence the industry's emission profile under the GHGRP. We also anticipate that we could use this kind of information to better understand methane emission control practices at silicon carbide facilities, to improve the EPA's knowledge of CH4 emissions that may be useful for other CAA programs, or to support future climate change policies, non-regulatory initiatives, or regulations under the CAA. The proposed data could also be used to help estimate CH4 emissions from silicon carbide facilities at the national level, and thereby inform and improve the U.S. GHG Inventory by allowing for more accurate estimates that account for CH4 removal.
We are also proposing that for each CH4 abatement technology, reporters must either use the manufacturer's specified destruction efficiency or the destruction efficiency determined via a performance test; if the destruction efficiency is determined via a performance test, reporters must also provide the name of the test method that was used during the performance test. We note that the collection of data elements related to GHG abatement and methane destruction are consistent with other subparts such as subparts E (Adipic Acid Production), I (Electronics Manufacturing), V (Nitric Acid Production), HH (Municipal Solid Waste Landfills), and FF (Underground Coal Mines) of Part 98. For these subparts, reporters are typically provided an option to account for the destruction of methane in their estimated emissions (e.g., fluorinated gases abated in electronics manufacturing processes or collection and destruction of methane at MSW facilities) and provide similar information on the type of abatement technology, hours of operation, and destruction or control efficiencies. This data is typically used for verification of emissions estimates and to confirm where process technologies or control measures result in minimal emissions. The collection of abatement data from silicon carbide facilities would be consistent with this practice. Finally, we are proposing that upon reporting this information once in an annual report, reporters would not be required to report this information again unless the information changed during another reporting year, in which case, the reporter would update the information in the submitted annual report. However, if it appeared that operational practices change at facilities such that CH4 emissions are not consistently controlled from year to year or that unabated CH4 emissions may be a more substantive contributor to industry emissions, then the EPA may consider whether it would be beneficial to reintroduce CH4 calculation methodology and reporting requirements. We are proposing adding recordkeeping requirement 40 CFR 98.287(d) for facilities to maintain a copy of the reported data.
Based on review of available permits, we anticipate that reporters could obtain the proposed data elements from data that is collected and readily available to facilities as part of their standard operation. For example, as part of normal operations, we assume facilities would keep records of any time that the CH4 abatement technology was not in use; therefore, the facility could then calculate the percent of total operating hours that the abatement technology was not in use. We are soliciting comment on whether this assumption is correct. We are also proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
We are also seeking comment on alternative methods for determining destruction efficiency (i.e., methods other than using either the manufacturer's specified destruction efficiency or the destruction efficiency determined via a performance test). For example, we are considering whether it would be more reasonable to allow for the "lesser of manufacturer's specified destruction efficiency and 0.99," as is required in subpart HH.
N. Subpart DD  --  Electrical Transmission and Distribution Equipment Use
1. Proposed Revisions to Improve the Quality of Data Collected for Subpart DD
For the reasons discussed in section II.A.3 of this preamble, we are proposing several revisions to subpart DD of Part 98 (Electrical Transmission and Distribution Equipment Use) to improve the quality of the data collected from this subpart. These include adding F-GHGs other than SF6 and PFCs to the monitoring, calculation, and reporting requirements of subpart DD (at 40 CFR 98.302, 98.303, 98.304, 98.305, and 98.306), clarifying the definition in 40 CFR 98.308 for "facility," adding definitions for "energized," "insulating gas," "new equipment," and "retired equipment," and specifying procedures in 40 CFR 98.303(b) for establishing user-measured nameplate capacity values for new and retiring equipment.
Currently, this subpart includes all electric transmission and distribution equipment and servicing inventory insulated with or containing SF6 or PFCs used within an electric power system. We are proposing to revise the existing calculation, monitoring, and reporting requirements of subpart DD to require reporting of additional F-GHGs as defined under 40 CFR 98.6. At the time of the 2010 final rule, SF6 was the most commonly used insulating gas in the electrical power industry, and PFCs were occasionally used as dielectrics and heat transfer fluids in power transformers. During the implementation of the reporting program, electrical power systems equipment manufacturers and F-GHG suppliers have introduced alternative technologies and replacements for SF6 with lower GWPs, including fluorinated gas mixtures, such as fluoronitriles or fluoroketones mixed with carrier gases (e.g., CO2 and O2), as a replacement for dielectric insulation gases. The GWPs of these gases are generally much lower than the GWP of SF6; the GWPs of fluoronitrile mixtures are typically estimated to fall between 300 and 500, whereas the GWPs of fluoroketone mixtures are usually estimated to be less than 1. The EPA is aware that some electric power systems are currently using or considering use of these alternative gas mixtures; therefore, we are proposing revisions to the reporting requirements in order to capture emissions from equipment using these alternative gases that are not currently accounted for. While the use of alternative insulation gases will generally result in lower GHG emissions, we would expect that that increased usage of these alternative technologies, particularly fluoronitrile mixtures, could still significantly contribute to the total GHG emissions from this sector if used in large quantities. The proposed reporting of these additional F-GHGs would improve the accuracy and completeness of the emissions reported under subpart DD and enhance the overall quality of the data collected under the GHGRP.
To implement these revisions, we are proposing at 40 CFR 98.300(a) to redefine the source category to include equipment containing "fluorinated GHGs (F-GHGs), including but not limited to sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs)." As discussed in section III.N.2 of this preamble, the proposed changes would also apply to the threshold in 40 CFR 98.301. Under the proposed rule, both electric power systems and electric generating units with insulated equipment would also consider any additional F-GHGs, including those in F-GHG mixtures, used at the facility in the nameplate capacity used for estimating the threshold. At this time, we are unaware of any facilities that currently use the alternative gas mixtures exclusively or in large quantities that would render them newly subject to the subpart; therefore, we expect the minimal burden from the proposed requirements would fall on existing reporters, who would only be required to account for the additional F-GHGs in their gas-insulated equipment (GIE) and inventory.
The proposed revisions to subpart DD include minor revisions to Equation DD-1 (which would be redesignated as Equation DD-3 at 40 CFR 98.303(a) under this proposed rule) to incorporate the estimate of emissions from all F-GHGs within the existing calculation methodology, including F-GHG mixtures. Equation DD-3 would maintain the facility-level mass balance approach of tracking and accounting for decreases, acquisitions, disbursements, and net increase in total nameplate capacity for the facility each year, but would require applying the weight fraction of each F-GHG to determine the user emissions by gas. It is our understanding that facilities receive gas in equipment pre-mixed and do not mix the gas themselves; therefore, the proposed revisions assume that facilities will track the mixtures received, and rely on supplier data to obtain the weight fraction of each F-GHG within equipment containing a gas mixture. Facilities would need to track mixtures with unique weight fractions of individual F-GHGs separately. However, we are seeking comment on whether the weight fraction of individual F-GHGs is readily available from supplier data. We are also seeking comment on whether there are facilities that mix gas in equipment on site, or that expect to mix gas in equipment at the facility in the future, and whether we should account for this mixing in the current equation. Since we assumed that gases are typically received pre-mixed, the proposed changes include reporting of an ID number or descriptor for each insulating gas and the name and weight percent of each fluorinated gas of each insulating gas reported. To simplify references to F-GHGs and F-GHG mixtures throughout the subpart (especially in Equation DD-3), we are proposing to introduce the term "insulating gas" and to define it as follows: "Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc quenching gas in electrical equipment." The proposed changes also include updating the monitoring and quality assurance requirements at 40 CFR 98.304(b) to account for emissions from additional F-GHGs, and harmonizing revisions to the term "facility" in the definitions section at 40 CFR 98.308, and the requirements at 40 CFR 98.302, 40 CFR 98.305, and 40 CFR 98.306 such that reporters would account for the mass of each F-GHG for each electric power system. The proposed changes would not significantly revise the existing calculation, monitoring, or reporting requirements; therefore, we expect only a minimal increase in burden due to the collection of data for any equipment containing F-GHGs that are not SF6 or PFCs. We are proposing related confidentiality determinations for the revised data elements that incorporate additional F-GHGs, as discussed in section VI of this preamble. We are proposing one additional change to remove an outdated monitoring provision at 40 CFR 98.304(a), which reserves a prior requirement for use of BAMM that applied solely for RY2011.
For the reasons described in section II.A.5 of this preamble, we are also proposing to add new definitions to clarify the existing provisions of the rule. The mass balance methodology in 40 CFR 98.303 (used for calculating facility emissions) uses the terms "new" and "retired" to describe equipment added to or removed from active use, and reporters are required to report nameplate capacity and the number of F-GHG containing pieces of any new and retired equipment. We have previously received questions from reporters regarding what equipment should be included as new or retired equipment each year, and we developed interpretations of these terms for our list of Frequently Asked Questions. We are proposing to adopt the previous interpretations into the rule's requirements in order to help ensure that reporters correctly estimate emissions, which would improve the quality of the data collected. The proposed revisions would also reduce time spent searching the list of Frequently Asked Questions or responding to questions through the GHGRP Help Desk.
First, we are proposing a definition at 40 CFR 98.308 of "energized" to more clearly designate what equipment is considered to be installed and functioning as opposed to being in storage. The proposed definition clarifies that energized equipment includes gas-insulated equipment (including hermetically-sealed pressure switchgear) that is connected through busbars or cables to an electrical power system or that is fully-charged, ready for service, and being prepared for connection to the electrical power system, and does not include spare GIE (including hermetically-sealed pressure switchgear) in storage that has been acquired by the facility, and is intended for use by the facility, but that is not being used or prepared for connection to the electrical power system. Consistent with our previous interpretation, we are proposing to add a definition for "new equipment" to mean any GIE, including hermetically-sealed pressure switchgear, that is not energized at the beginning of the reporting year, but is energized at the end of the reporting year. Similarly, we are proposing a definition for "retired equipment" to mean any GIE, including hermetically-sealed pressure switchgear, that is energized at the beginning of the reporting year, but is not energized at the end of the reporting year. Finally, we are clarifying that (1) new equipment may also include equipment that has been transferred while in use, meaning it has been added to the facility's inventory without being taken out of active service (e.g., when the equipment is sold to or acquired by the facility while remaining in place and continuing operation), and (2) retired equipment may also include equipment that has been transferred while in use, meaning it has been removed from the facility's inventory without being taken out of active service (e.g., when the equipment is acquired by a new facility while remaining in place and continuing operation).
The proposed definitions of "energized," "new equipment," and "retired equipment" are intended to clarify how these terms should be interpreted for purposes of the equation used to estimate emissions for annual reporting (i.e., the current Equation DD-1, which we are proposing to redesignate as Equation DD-3). This equation uses a mass-balance approach that assesses annual net gas consumption (based on the decrease in gas inventory and gas acquisitions and disbursements) and accounts for gas used or freed up, respectively, by equipment installations and retirements. The nameplate capacity of new equipment is subtracted from the total, reflecting the fact that some of the insulating gas consumed is used to fill the new equipment, while the nameplate capacity of retiring equipment is added to the total, reflecting the fact that the gas formerly used to fill the retiring equipment, unless emitted, would either be added to the gas inventory or disbursed (e.g., to an SF6 recycling company). Implicit in this approach are the assumptions that "new" equipment is filled with insulating gas during the same year that it is considered "new," and that "retired" equipment is emptied of insulating gas during the same year that it is considered "retired." We request comment on whether new equipment is typically filled with gas during the same year that it is "energized" under the proposed definition of "energize," and on whether retiring equipment is typically emptied of gas during the same year that it ceases to be "energized" under the proposed definition. If gas is added to or removed from "new" and/or "retired" equipment in a year different from the year that the equipment is energized or ceases to be energized, respectively, it may be clearer to directly tie the terms "new" and "retired" to the filling and emptying of the equipment (for closed-pressure equipment).
In 40 CFR 98.303(b) we are proposing to require users of electrical equipment to follow certain procedures when they elect to measure the nameplate capacities (in units of mass of insulating gas) of new and retiring equipment rather than relying on the rated nameplate capacities provided by equipment manufacturers. This option would be available only for closed-pressure equipment with a voltage capacity greater than 38 kV, not for hermetically sealed pressure equipment or smaller closed-pressure equipment. The procedures are intended to ensure that the nameplate capacity values that equipment users measure match the full and proper charges of insulating gas in the electrical equipment. These procedures are also intended to be similar to and compatible with the procedures proposed by the California Air Resources Board (CARB) on May 5, 2021 and revised on June 17, 2021, for measurements of nameplate capacity by electrical equipment users in California.
As discussed above, the nameplate capacities of new and retiring electrical equipment are used in the current Equation DD-1 of subpart DD (which would be redesignated as Equation DD-3 under this proposed rule), which calculates annual GHG emissions from the equipment. In the equation, nameplate capacity is defined as referring to "the full and proper charge of equipment rather than to the actual charge, which may reflect leakage." With each piece of electrical equipment, electrical equipment manufacturers typically provide a rated nameplate capacity in pounds of SF6 (or other insulating gas) on a nameplate affixed to the equipment and/or in the product specifications. When the EPA promulgated subpart DD, we expected that users of electrical equipment would be able to use these rated nameplate capacities in their emissions calculations without introducing any errors. Experience has shown, however, that even when users of electrical equipment follow industry-accepted equipment filling and gas measuring methods, the mass of insulating gas contained in the equipment when it is filled to the manufacturer-specified density can sometimes differ from that specified on the nameplate. That is, the actual nameplate capacity of the equipment (the full and proper charge) can differ from the rated nameplate capacity of the equipment.
Differences between the actual and rated nameplate capacities may result in either under- or over-estimates of emissions in the short run, depending on: (1) whether the actual nameplate capacity is greater than the rated nameplate capacity or vice versa; and (2) whether the equipment is being commissioned or retired. For example, if the actual nameplate capacity of new equipment is larger than the rated nameplate capacity of that equipment, emissions will be overestimated, because some of the gas that was actually used to fill the new equipment will be assumed to have been emitted. On the other hand, if the actual nameplate capacity of retiring equipment is larger than the rated nameplate capacity of the equipment, emissions will be underestimated (and may even be calculated as negative), because the quantity of gas recovered or emitted from the retiring equipment will be larger than is accounted for by the equation. (More scenarios are described in the document Technical Support for Proposed Revisions to Subpart DD (2021) included in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.)
As the above example shows, these underestimates and overestimates from a piece of equipment would cancel out over the lifetime of the equipment. To some extent, they may also cancel out in any given year because rated nameplate capacities can be either larger or smaller than the actual nameplate capacities, and most electrical equipment users are likely to both install and retire several pieces of equipment during the year. However, if a large piece of electrical equipment (or several smaller pieces of electrical equipment) is installed or retired in a given year, an error in the rated nameplate capacity of that equipment could potentially have a significant impact on the calculated emissions from the electrical equipment user in that year.
For this reason, when electrical equipment users have asked the EPA via the Helpdesk whether they may use a nameplate capacity value different from the rated nameplate capacity value in their calculations and reporting under subpart DD, we have responded that they may use the nameplate capacity value that corresponds to the full and proper charge of the equipment, which is determined based on density (e.g., the temperature-corrected pressure of the equipment) per the manufacturer's filling instructions. We have also noted that subpart DD does not currently specify a method for calculating nameplate capacity values, but for the mass-balance approach to yield correct results, the nameplate capacity value should reflect any shipping charge contained in the equipment upon delivery, and the same nameplate capacity value should be used throughout the life of the equipment. Finally, we have noted that paragraph 98.3(g)(2) requires equipment users to keep records of the method used to calculate the nameplate capacity value.
The process that we are proposing in this action would elaborate on and adopt this guidance into the rule's requirements. It is designed to avoid a number of potential errors by equipment users that can result in inaccuracies in the nameplate capacities that they measure. Such errors can occur when:
Equipment is deliberately overfilled or underfilled;
Shipping charges are accounted for incorrectly or not at all;
Inaccurate weigh scales, flowmeters, pressure gauges, or thermometers are used to fill equipment;
The temperature of the insulating gas is not measured accurately when the equipment is filled or emptied (e.g., the temperature of the gas is incorrectly equated to the ambient temperature);
The insulating gas in equipment (especially retiring equipment) is not completely recovered (or the gas remaining in the equipment is not accounted for);
Previous leakage from equipment (especially retiring equipment) is not accounted for; or
Insulating gas in hoses and gas carts is not accounted for.
To avoid these potential errors, the EPA is proposing certain requirements at 40 CFR 98.303(b) for when electrical equipment users measure the nameplate capacity of new equipment that they install. These proposed requirements for new equipment would help ensure that electrical equipment users:
Correctly account for the mass of insulating gas contained in equipment upon delivery from the manufacturer (i.e., the holding charge);
Use flowmeters or weigh scales that meet certain accuracy and precision requirements to measure the mass of insulating gas added to the equipment;
Use pressure-temperature charts and pressure gauges and thermometers that meet certain accuracy and precision requirements to fill equipment to the density specified by the equipment manufacturer, allowing appropriate time for temperature equilibration; and
Ensure that insulating gas remaining in hoses and gas carts is correctly accounted for.
The EPA is also proposing certain requirements at 40 CFR 98.303(b) for when electrical equipment users measure the nameplate capacity of retiring equipment. These proposed requirements for retiring would help ensure that electrical equipment users:
Correctly account for the mass of insulating gas contained in equipment upon retirement, measuring the actual temperature-adjusted pressure and comparing that to the temperature-adjusted pressure that reflects the correct filling density of that equipment;
Use flowmeters or weigh scales that meet certain accuracy and precision requirements to measure the mass of insulating gas recovered from the equipment;
Use pressure-temperature charts and pressure gauges and thermometers that meet certain accuracy and precision requirements to recover the insulating gas from the equipment to the correct blank-off pressure, allowing appropriate time for temperature equilibration; and
Ensure that insulating gas remaining in the equipment, hoses and gas carts is correctly accounted for.
We are proposing at 40 CFR 98.303(b)(6) that instead of measuring the nameplate capacity of electrical equipment when it is retired, users may measure the nameplate capacity of electrical equipment earlier during maintenance activities that require opening the gas compartment. In this case, the equipment user would still be required to follow the measurement procedures required for retiring equipment at 40 CFR 98.303(b)(5) to measure the nameplate capacity, and the measured nameplate capacity would be recorded but would not be used in Equation DD-3 until that equipment was actually retired.
As previously mentioned, only closed-pressure equipment with a voltage capacity greater than 38 kV would be eligible for nameplate capacity measurement and correction. This is because the quantities of insulating gas that are typically inside hermetically sealed-pressure equipment and in closed pressure equipment with smaller voltage capacities are individually and collectively less significant than those in closed-pressure equipment with voltage capacities at or above 38 kV. Consequently, any errors in the rated nameplate capacities of smaller equipment are not likely to have a significant impact on the calculated emissions of equipment users, and efforts to correct the nameplate capacity values of smaller equipment do not appear to be justified by the improvement in accuracy that would result. CARB has established eligibility criteria similar to those we are proposing based on their finding that the criteria would cover "approximately 23 percent of California's GIE [gas insulated equipment] and approximately 80 percent of the SF6 used in the State." In addition, users rarely add or remove gas to or from hermetically sealed-pressure equipment, by design. We request comment on the proposed eligibility criteria.
We are proposing a scheme in 40 CFR 98.303(b) that would require all eligible new and retiring equipment to be treated consistently with respect to the measurement and adoption of nameplate capacities. To avoid biases that could result from measuring and adopting nameplate capacities for some pieces of eligible new or retiring equipment but not others, electrical equipment users electing to measure the nameplate capacities of any new or retiring equipment would be required at 40 CFR 98.303(b)(1) to measure the nameplate capacities of all eligible new and retiring equipment in that year and in all subsequent years. For each piece of equipment, the electrical equipment user would be required to calculate the difference between the user-measured and rated nameplate capacities, verifying that the rated nameplate capacity was the most recent available from the equipment manufacturer. Where a user-measured nameplate capacity differed from the rated nameplate capacity by two percent or more, the electrical equipment user would be required at 40 CFR 98.303(b)(2) to adopt the user-measured nameplate capacity for that equipment for the remainder of the equipment's life. Where a user-measured nameplate capacity differed from the rated nameplate capacity by less than two percent, the electrical equipment user would have the option at 40 CFR 98.303(b)(3) to adopt the user-measured nameplate capacity, but if they chose to do so they would be required to adopt the user-measured nameplate capacities for all new and retiring equipment whose user-measured nameplate capacity differed from the rated nameplate capacity by less than two percent. As is the case for the proposed requirement to consistently measure or not measure the nameplate capacities of all new and retiring equipment, the proposed requirement to consistently adopt or not adopt the user-measured nameplate capacities where they differ from the rated nameplate capacity by less than two percent is intended to avoid bias that could result from adopting only a subset of the user-measured nameplate capacities that fall into this category.
We are proposing the two-percent tolerance for differences between the user-measured and rated nameplate capacities because, given the precisions and accuracies that we are proposing for the measuring devices (scales, gauges, etc.) used to calculate nameplate capacities (as discussed further in this section), differences of one percent or less are not expected to be mathematically meaningful. We request comment on the value of two percent and on whether the percentage tolerance should be supplemented by an absolute tolerance, such as 100 pounds of SF6 (equivalent to 1,034 mtCO2e). In the latter case, differences equal to or greater than the lesser of two percent or 100 pounds would trigger the requirement to use the user-measured nameplate capacity. The drawback of using a separate absolute tolerance is that this tolerance may not be mathematically meaningful if the full and proper charge of the equipment exceeded 10,000 pounds.
Our proposal to allow electrical equipment users to adopt the user-measured nameplate capacity even when the difference between that capacity and the rated capacity is less than two percent is based on our desire to maintain as much consistency as possible between GHGRP requirements and the proposed requirements of CARB. Our understanding is that CARB is proposing to require electrical equipment users in California to measure the nameplate capacity of all newly installed closed pressure equipment with a voltage capacity greater than 38 kV and to adopt the measured value irrespective of the magnitude of the difference between the measured value and the manufacturer-supplied value.
When electrical equipment is retired, the quantity of the gas remaining in the equipment may reflect leakage that has occurred since the last time the equipment was serviced or re-filled. In this case, we are proposing at 40 CFR 98.303(b)(5) to allow equipment users to account for the leakage using one of two approaches. In both approaches, equipment users would: (1) measure the temperature-compensated pressure of the equipment before they removed the insulating gas from that equipment; and (2) compare the measured temperature-compensated pressure to the temperature-compensated pressure corresponding to the full and proper charge of the equipment (the design operating pressure). If the measured temperature-compensated pressure was different from the temperature-compensated pressure corresponding to the full and proper charge of the equipment, the equipment user could either (a) add or remove insulating gas to or from the equipment until the equipment reached its full and proper charge, recover the gas until the equipment reached a pressure of 0.068 pounds per square inch, absolute (psia) (3.5 Torr) or less, and weigh the recovered gas (charge adjustment approach), or (b) if the measured temperature-compensated pressure was at least 90 percent of the temperature-compensated design operating pressure, recover the gas that was already in the equipment, weigh it, and account mathematically for the difference between the quantity of gas recovered from the equipment and the full and proper charge (mathematical adjustment approach). In the mathematical adjustment approach, the equipment user would calculate the mass of the full and proper charge by scaling up the mass recovered by the ratio of pressures (in absolute terms) corresponding to the full and proper charge and the actual charge, respectively, accounting for any insulating gas remaining in the equipment (if the final pressure of the equipment exceeded 0.068 psia). We are proposing to limit the mathematical adjustment approach to situations where the measured temperature-compensated pressure is equal to or greater than 90 percent of the design operating pressure to ensure that nameplate capacity measurements and calculations remain precise. If smaller fractions of the full charge are scaled up to calculate the nameplate capacity, the uncertainty of the calculation begins to approach (and ultimately exceed) two percent given the precision and accuracy requirements we are proposing for pressure gauges and other measurement devices. We request comment on the expected accuracy of the mathematical adjustment approach, and whether it might be affected by any non-linearities in the relationship between pressure and density. One way of addressing such non-linearities, if they exist, may be to include a compressibility factor (often termed a "Z" factor) in the calculation, as we have done for gas measurements for other subparts (see, e.g., Equation I-25 of subpart I (Electronics Manufacturing) and Equation L-33 of subpart L (Fluorinated Gas Production) of Part 98). The mathematical adjustment approach would accommodate situations where it may not be possible to fully recover the insulating gas from the equipment, e.g., where the equipment has leaks through which air would be drawn into the equipment and subsequently into the recovery equipment or gas cart if the equipment were drawn into a deep vacuum. (CARB is proposing an exception to its nameplate capacity measurement requirements for equipment with "compromised integrity.") The mathematical adjustment approach would also avoid some of the disadvantages of the charge adjustment approach, which, compared to the mathematical adjustment approach, would be more time-consuming and risks emitting more insulating gas and contaminating the insulating gas used to top up the equipment with impurities in the gas that remains in the equipment.
To ensure that the mass-balance method is based on consistent nameplate capacity values throughout the life of the equipment, we are proposing at 40 CFR 98.303(b)(9) that electrical equipment users would be allowed to measure and revise the nameplate capacity value of any given piece of equipment only once, unless the nameplate capacity itself is likely to have changed due to changes to the equipment (e.g., replacement of the equipment bushings).
Currently, subpart DD requires that scales used to measure cylinders of gas be accurate and precise to within 2 pounds of true weight and be periodically recalibrated per the manufacturer's specifications. Subpart DD does not include accuracy or precision requirements for other measuring devices, such as flow meters, pressure gauges, or thermometers. To help ensure that electrical equipment users obtain accurate measurements of their equipment's nameplate capacities, we are therefore proposing at 40 CR 98.303(b)(10) that electrical equipment users use measurement devices that meet the following accuracy and precision requirements when they measure the nameplate capacities of new and retiring equipment.
(1) Flow meters must be certified by the manufacturer to be accurate to within one percent of the largest value that the flow meter can, according to the manufacturer's specifications, accurately record.
(2) Pressure gauges must be certified by the manufacturer to be accurate within 0.5 percent of the largest value that the gauge can, according to the manufacturer's specifications, accurately record.
(3) Temperature gauges must be certified by the manufacturer to be accurate within +/-1.0° F; and
(4) Scales must be certified by the manufacturer to be accurate to within one percent of the true weight.
These accuracy and precision requirements are the same as those proposed by CARB in its May 5, 2021 and June 17, 2021 notices. The measurement devices listed here would be subject to the general GHGRP calibration requirements at 40 CFR 98.3(i).
Even if electrical equipment users use an accurate thermometer, they may under- or overestimate the temperature of the gas being filled into the equipment or recovered from it, for example if they assume that the gas is at the same temperature as the area surrounding the equipment. This is because gas that is filled into equipment from a container may be cooler or warmer than the ambient temperature depending on the method used to transfer the gas. Where the insulating gas is pulled from the container in the liquid phase, an evaporator is generally used between the container and the equipment to ensure that only gas is transferred into the electrical equipment. A representative of a gas cart manufacturer indicated that the gas transferred using this method is often slightly warmer than the ambient temperature. In this case, the density of the gas will be lower than the density calculated using the ambient temperature. Where the insulating gas is pulled from the container in the gas phase, the container (and the gas inside) tends to cool as the gas boils off from a reservoir of liquid insulating gas in the container. Heating blankets are often used to warm the container and gas in this case, but they may not compensate for the temperature loss associated with the phase change. In this case, the gas will be cooler than the ambient temperature, and its density will be higher than the density calculated using the ambient temperature. To at least partly address these issues, we are proposing to require that equipment users measure the temperature of the electrical equipment rather than relying on the ambient temperature when making nameplate capacity measurements. However, even measurements on the surface of the electrical equipment may not reflect the temperatures inside, at least not right away. To ensure that the temperature of the gas is not under- or overestimated, we are considering requiring a minimum temperature equilibration time following the gas filling procedure. We request comment on this option, including on what appropriate waiting times would be for temperature equilibration for equipment of different sizes and on whether manufacturer filling directions adequately address temperature measurement issues. Temperature equilibration times that we are considering range from 30 minutes for relatively small equipment to 8 to 24 hours for large equipment.
We also request comment on whether it would be sufficient to require that any gas inside hoses is "accounted for" both before and after equipment filling or emptying processes, or whether we should specify a more detailed procedure for evacuating hoses before and after equipment filling and emptying. A representative of a gas cart manufacturer who commonly provides training on use of its gas carts described the following procedure to the EPA: Any gas in the hoses should be pulled back into the gas cart/cylinders before the filling or emptying process begins, and the baseline measurements on scales and/or flow meters should be taken at that point. Then the equipment should be filled or emptied, the hoses should be isolated from the equipment, and any remaining gas in the hoses should be pulled back into the gas cart/cylinders. At that point the final measurements on scales and/or flow meters should be taken. We request comment on whether we should require use of this procedure or whether there may be other acceptable procedures for ensuring that any gas in hoses is accounted for in nameplate capacity measurements.
We are proposing at 40 CFR 98.307(b) to require equipment users to keep records of certain identifying information for each piece of equipment for which they measure the nameplate capacity: the rated and measured nameplate capacities, the date of the nameplate capacity measurement, the measurements and calculations used to obtain the measured nameplate capacity (including the temperature-pressure curve and/or other information used to derive the initial and final temperature-adjusted pressures of the equipment), and whether or not the measured nameplate capacity value was adopted for that piece of equipment. In addition, we are proposing at 40 CFR 98.306(o) and (p) to require equipment users who measure and adopt nameplate capacity values to report the total rated and measured nameplate capacities across all the equipment whose nameplate capacities were measured and for which the measured nameplate capacities have been adopted in that year. Collecting this information would help enable us to ascertain the average magnitude of nameplate capacity adjustments at both the facility and U.S. level, providing insight into the extent to which manufacturer-assigned nameplate capacities may err and alerting us to situations where adjustments are unusually large, which may indicate that equipment users are not following the procedures specified in the rule to ensure that they measure nameplate capacity values accurately.
2. Proposed Revisions to Streamline and Improve Implementation for Subpart DD
In alignment with our proposed revisions to include additional F-GHGs in the source category, and for the reasons described in section II.B.1 of this preamble, we are proposing to revise the applicability threshold of subpart DD at 40 CFR 98.301. Subpart DD currently requires reporting from facilities with a total nameplate capacity of SF6 and PFC-containing equipment located within the facility or under common ownership or control exceeding 17,820 pounds. The EPA established the nameplate capacity threshold of 17,820 pounds in the December 1, 2010 final rule (75 FR 74774) as an "equivalent threshold" that approximated the 25,000 metric tons of CO2 threshold for emissions. Emissions of SF6 and PFC from the source category include emissions from equipment leaks and venting from gas-insulated substations and switch gear. The insulating gas can also be released during equipment manufacturing, installation, normal operation and maintenance, and disposal. We initially chose a nameplate capacity-based threshold because nameplate capacity is strongly correlated with SF6 emissions, and a capacity-based threshold allows potential sources to determine whether they are above or below the threshold more quickly and with less effort than through estimating emissions. The threshold of 17,820 pounds was estimated using the GWP of SF6 that was applicable at the time and historical leakage data reported by industry owners and operators who are partners in EPA's SF6 Emission Reduction Partnership for Electric Power Systems.
To help ensure that the GHGRP data collected better reflects the emission rates and insulating gases that prevail in the current electric power system industry, we are proposing to replace the existing nameplate capacity threshold with an emissions threshold of 25,000 metric tons CO2e per year of F-GHGs. To calculate their F-GHG emissions for comparison with the threshold, electrical equipment users would use one of two new equations in subpart DD at 40 CFR 98.301, proposed Equations DD-1 and DD-2. The proposed equations explicitly include not only the nameplate capacity of the equipment but also an updated default emission factor and the GWP of each insulating gas. The equations would therefore account for additional fluorinated gases (including GHG mixtures) now being marketed to the industry as well as lower reported emission rates within the industry. The current nameplate-capacity based threshold was based on the historical emission rate, which was estimated at approximately 13 percent, and the GWP for SF6. For small facilities (total nameplate capacity between 17,000 and 50,000 lbs), the largest emission rate reported since 2013 (based on beginning of year capacity) was 10.3 percent. Additionally, some facilities within this industry sector may have begun to use lower GWP F-GHGs, which is not reflected when using only nameplate capacity of the equipment to determine applicability. Therefore, the current nameplate capacity threshold may require facilities with annual subpart DD emissions below 25,000 mtCO2e per year to report. Revising the reporting threshold to account for lower emission rates and the use of F-GHGs with lower GWPs would reduce burden for those electric power systems and facilities that have decreased their reliance on SF6-insulated equipment and would maintain a threshold equivalent to the 25,000 mtCO2e threshold.
As discussed in section III.N.1 of this preamble, we are proposing to revise the existing calculation, monitoring, and reporting requirements of subpart DD to require reporting of additional F-GHGs beyond SF6 and PFCs. Therefore, the proposed new Equations DD-1 and DD-2 that we are proposing for the applicability threshold would require potential reporters to account for the total nameplate capacity of all F-GHG containing equipment (located on-site and/or under common ownership or control), including equipment containing F-GHG mixtures, and multiply by the weight fraction of each F-GHG (for gas mixtures), the GWP for each F-GHG, and an emission factor of 0.10 (representing an emission rate of 10 percent). We have determined that the proposed threshold methodology is more appropriate because it represents the actual fluorinated gases used by a reporter, accounts for gas mixtures, and updates the contemporaneous emission rate performance for the industry. Finally, we are proposing harmonizing changes in multiple subsections to renumber existing Equation DD-1 and maintain cross-references to the equation.
The proposed revisions would also streamline the reporting requirements to focus Agency resources on the substantial emission sources within the sector and would exclude new electric power systems and other new facilities from subpart DD when their emissions of insulating gas were estimated to be below 25,000 mtCO2e per year. The proposed changes would revise the existing threshold in 40 CFR 98.301 and Table A-3 to subpart A (General Provisions). Reporters would continue to determine the applicability of subpart DD under 40 CFR 98.2(a)(1), which applies to source categories listed in Table A-3, such that only total estimated emissions from F-GHGs would be accounted for in determining whether the applicability threshold is met. Therefore, facilities would continue to determine the applicability of subpart DD without consideration of the combined emissions from stationary fuel combustion sources (subpart C), miscellaneous use of carbonates (subpart U), and other applicable source categories towards the threshold.
Due to the definition of "facility" for electric power systems that is different from the definition of "facility" (in subpart A of Part 98) that covers facilities in other subparts, electric power systems always report to the GHGRP as unique facilities (i.e., emissions from other sources covered by the GHGRP that may have overlap in location with a subpart DD facility are reported under a different e-GGRT identifier due to the different definition of "facility"). Thus, placement of subpart DD in Table A-3 or Table A-4 of subpart A has no effect on the emissions considered when determining applicability for electric power systems if an equivalent threshold is used. However, for other facilities that use electrical equipment, it is possible to add emissions under subpart DD to those from other subparts as they use the standard definition of "facility" in Subpart A. We are currently proposing to maintain subpart DD in Table A-3 of subpart A. By keeping subpart DD in Table A-3, we expect to continue to capture the majority of annual emissions from the use of electrical transmission and distribution equipment (approximately 65 percent in 2019; down from a high of 73 percent due to some facilities becoming eligible to exit the program) while not significantly increasing burden. Moving subpart DD to Table A-4 of subpart A would likely have a significant impact on the number of reporters subject to subpart DD but is unlikely to result in a significant increase to the proportion of emissions covered by the GHGRP, because moving subpart DD to Table A-4 would only affect facilities that are not electric power systems. Facilities that are not electric power systems have historically reported emissions significantly below 25,000 mtCO2e even when the total nameplate capacity at the facility was over the current threshold of 17,820 lbs. One option that we are considering is to move use of electrical equipment to Table A-4 of subpart A, which would require facilities that used electrical equipment but that were not electric power systems to determine applicability according to 40 CFR 98.2(a)(2). Under this option, facilities that used electrical equipment but that were not electric power systems would be required to add their total estimated F-GHG emissions from electrical equipment to their combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all other applicable source categories that are listed in Table A-3 and Table A-4 to determine whether the facility emits 25,000 mtCO2e or more per year in combined emissions and whether they were required to report under Part 98. In other words, if the result of this calculation exceeded 25,000 mtCO2e, they would be required to report their emissions from electrical equipment even if the F-GHG emissions from such equipment, by themselves, were below 25,000 mtCO2e. We are considering requiring more comprehensive reporting of emissions from users of electrical equipment other than electric power systems because comparisons between the consumption of SF6 reported to the GHGRP by SF6 suppliers have generally exceeded the consumption reported by (or estimated by the EPA for) SF6 users. It is possible that SF6 consumption by users of electrical equipment with nameplate capacities under the current threshold (and therefore with SF6 emissions that are likely to fall under the 25,000 mtCO2e threshold) could account for some of this gap, and therefore it is possible that reporting by these facilities would at least partially explain the gap. However, we recognize that if we move subpart DD to Table A-4, numerous facilities that are subject to this part because of emissions from another source category would potentially be newly required to report under subpart DD with only a few pieces of gas-insulated equipment. One option for addressing this concern would be not to require reporting when emissions from the facility's electrical equipment, as calculated using Equation DD-2, fell below a threshold, such as 1,000 mtCO2e. We request comment on these options.
O. Subpart FF  --  Underground Coal Mines
The EPA is proposing two technical corrections to subpart FF of Part 98 (Underground Coal Mines), for the reasons described in section II.A.5 of this preamble. First, we are proposing to correct the term "MCFi" in Equation FF-3 of subpart FF to revise the term "1-(fH2O)l" to "1-(fH2O)i." The proposed change would correct an error inadvertently introduced in the November 29, 2013 final rule (78 FR 71967). Second, we are proposing a revision to 40 CFR 98.326(t). Facilities are required to report the Mine Safety and Health Administration (MSHA) identification number to the EPA. The technical correction would add the word "number" after the word "identification" to clarify the reporting requirement.
P. Subpart GG  --  Zinc Production
We are proposing one revision to subpart GG of Part 98 (Zinc Production) that would improve the quality of the data collection under the GHGRP. For the reasons described in section II.A.4 of this preamble, we are proposing to add a reporting requirement at 40 CFR 98.336(a)(6) and (b)(6) for the total amount of EAF dust annually consumed by all Waelz kilns at zinc production facilities. EAF dust and other scrap materials are primary inputs at certain zinc production and recycling facilities from which zinc is recovered. The EPA is proposing to collect this data in order to improve verification of reported data under the GHGRP. This data would also improve emissions estimates developed as part of the U.S. GHG Inventory. Collection of this data would be useful for verification of data reported through the GHGRP by assisting with data validation. The amount of EAF dust consumed by facilities strongly correlates with process CO2 emissions. Therefore, the total amount of EAF dust consumed by all Waelz kilns could be used for comparison to emissions estimates and would be useful for verifying consistency in emissions over time. Additionally, the U.S. GHG Inventory uses Tier 1 methods from the 2006 IPCC Guidelines to estimate emissions from zinc produced. For primary zinc production, the inventory uses a Waelz kiln emission factor based on zinc production for non-EAF dust consuming facilities, and a Waelz kiln emission factor based on EAF dust consumption for EAF-dust consuming facilities. Currently, the EPA is only able to obtain EAF dust consumed for a small number of facilities using Waelz kilns, which increases the uncertainty of these emission factors. Further, for Waelz kiln-based production, the IPCC recommends the use of emission factors based on EAF dust consumption, since the amount of carbonaceous materials (e.g., coal or coke) used (which drives process CO2 emissions) is more directly dependent on the amount of EAF dust consumed, rather than the amount of zinc produced. Collecting the total annual EAF dust consumed for all Waelz kilns at facilities would allow the EPA to develop a more accurate emission factor for facilities using Waelz kilns for the Inventory.
Reporters currently estimate emissions using either a CEMS direct measurement methodology or calculate process CO2 emissions by determining annually the total mass of carbon-containing input materials (including zinc-bearing material, flux, electrodes, and any other carbonaceous materials) introduced into each kiln and furnace and the carbon content of each material. Of these materials, the proposed data element would only require segregation and reporting of the mass of EAF dust consumed for all kilns. Reporters currently collect information on the EAF dust consumed on a monthly basis as part of their existing operations; reporters using the mass balance methodology collect this data as a portion of the inputs to Equation GG-1. We are not proposing any changes to the mass calculation methodology; reporters would only be required to sum all EAF dust consumed on a monthly basis for each kiln and then for all kilns at the facility for reporting and entering the information into e-GGRT. Therefore, we do not anticipate that the proposed data elements would require any additional monitoring or data collection by reporters. The proposed data requirement would be required for reporters using either the CEMS direct measurement or mass balance calculation methodologies. We are also proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
Q. Subpart HH  --  Municipal Solid Waste Landfills
For the reasons described in section II.A.1 of this preamble, we are proposing revisions to subpart HH of Part 98 (Municipal Solid Waste Landfills) that would improve the quality of the data collection under the GHGRP. First, we are proposing to update the factors used in modeling CH4 generation from waste disposed at landfills to reflect the increased amount of inert materials that are disposed at landfills that do not contribute to CH4 generation. The updated factors would allow MSW landfills to more accurately model their CH4 generation.
Subpart HH uses a first order decay model to estimate CH4 generation from MSW landfills. This model considers the quantity of MSW landfilled, the degradable organic carbon (DOC) content of that MSW, and the first order decay rate (k) of the DOC. Table HH-1 of subpart HH contains DOC and k values that a reporter must use to calculate their CH4 generation based on the different categories of waste disposed at that landfill and the climate in which the landfill is located. The options available under the current rule can generally be summarized as follows:
The Bulk Waste option assumes a single stream of waste coming into the facility that contains a mixture of organic and inorganic wastes. The current default DOC for this waste stream is 0.20, and the default decay rate values for this bulk waste stream are dependent on precipitation rates: 0.02 for <20 inches of rainfall per year; 0.038 for 20-40 inches of rainfall per year; and 0.057 for >40 inches of rainfall per year.
The Modified Bulk MSW option allows facilities to break out their waste into three different streams: bulk MSW excluding inert and construction and demolition (C&D) wastes (effectively "organic MSW"); C&D waste; and inert waste. The decay rates for the "organic MSW" stream are the same as those listed for the Bulk Waste option, however the default DOC is a higher value of 0.31. This value was calculated from the waste quantities reported in the EPA's "Municipal Solid Waste in the United States: 2007 Facts and Figures" report specifically for the GHGRP considering only the organic containing portions of MSW.
The Waste Composition option provides defaults for DOC and k for several subcategories of waste including food waste, garden waste, paper waste, wood waste, inert waste, etc. The DOC and k values for different subcategories of wastes are based on the values recommended in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 5 Waste, Chapters 2 and 3. Reporters are allowed to use the waste composition option for those waste streams for which compositional data are available and use the bulk waste defaults (DOC and k values as described in the Bulk Waste option above) for waste streams where compositional data are not available.
The EPA has received comments from stakeholders in the waste industry (i.e., Waste Management, Republic Services, National Waste & Recycling Association, Solid Waste Association of North America, SCS Engineers, and Weaver Consulting Group) related to the values for DOC and k for both the Bulk Waste and Modified Bulk Waste Options listed under Table HH-1 to subpart HH. These comments were received during the expert and public comment review period for the U.S. GHG Inventory. The U.S. GHG Inventory for solid waste uses directly reported emissions values from subpart HH to estimate national CH4 emissions from MSW landfills throughout the entire United States, and the commenters noted that, in order to implement these suggested revisions to the U.S. GHG Inventory, revisions must first be made to subpart HH. Commenters argued, based on alleged fundamental shifts in the characterization of waste disposed in landfills and research conducted by state agencies and the Environmental Research and Education Foundation (EREF), that: (1) the default DOC values for Bulk Waste and Modified Bulk Waste overestimate the organic fraction of waste in U.S. landfills and therefore overestimate emissions from this source; and (2) that the EPA should perform an analysis of data reported to subpart HH and update the default k values as necessary based on the results of this analysis. Commenters noted that the default values for k currently listed in Table HH-1 of subpart HH for both the Bulk Waste and Modified Bulk Waste options are based on data from the EPA's 2008 draft AP-42: Compilation of Air Emissions Factors (which is still in draft form) and stated these default values are likely out-of-date considering changes in waste disposal trends in the past two decades.
In response, the EPA performed a multivariate analysis to minimize the difference between CH4 generation estimates back-calculated from the reported values of Equation HH-7 and the CH4 generation predicted using Equation HH-1, while optimizing k and DOC simultaneously for each landfill included in the analysis cohort. Six years of GHGRP data for 355 landfills were ultimately analyzed in this cohort. These 355 landfills were subpart HH reporters that reported a gas collection system (GCS) installed on-site for all reporting years, reported a consistent waste categorization option for all reporting years, and reported the same DOC and decay rate values for all reporting years. Details of this analysis are available in the memorandum from Meaghan McGrath, Kate Bronstein, and Jeff Coburn, RTI International, to Rachel Schmeltz, EPA, Multivariate analysis of data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), Subpart HH (Municipal Solid Waste Landfills) to optimize DOC and k values, (June 11, 2019), available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
After consideration of the comments received and the multivariate analysis performed, we are proposing to amend subpart HH to provide revised DOC and k values that would more accurately estimate GHG emissions from the MSW landfills. We are proposing to amend the bulk waste DOC value in Table HH-1 from 0.20 to 0.17, which was the average optimal DOC value for all landfills reporting under the Bulk Waste option (n=239) in the multivariate analysis. This value is similar to the proposed bulk waste DOC value of 0.161 the waste industry has cited within their comments as a result of study produced by the EREF (2016). We are proposing to use the results of the multivariate analysis in lieu of using the EREF recommended DOC value because the multivariate analysis is more nationally representative. EREF develop their recommended DOC value using state-level data for a single year (2013) for 14 states. The multivariate analysis based on subpart HH reported data uses facility-level data covering 41 states over the course of 6 years (2012-2017).
It was not possible to use the multivariate analysis to develop an optimal DOC value for bulk MSW waste without inerts and (C&D) waste for the Modified Bulk Waste option due to a lack of reporters that used this option meeting the criteria developed and noted above for the multivariate analysis. Instead, we reanalyzed the DOC value for this option using the same approach used to develop this factor initially but with updated MSW composition data from 2011 to 2015 as reported by the EPA. The average DOC value across the 5-year period considering all MSW landfilled is 0.17, which agrees well with our optimized DOC value for bulk MSW from the multivariate analysis. After subtracting out inerts, the average DOC for MSW excluding inerts is 0.27. The percent reduction of the DOC value for MSW excluding inerts is similar to the percent reduction in the average DOC for bulk MSW as determined from the multivariate analysis. Therefore, we are also proposing to revise the DOC value for the Modified Bulk MSW option in Table HH-1 from 0.31 to 0.27.
The EPA is also proposing to include a DOC value for "Uncharacterized MSW" within the Waste Composition option in Table HH-1. Currently, reporters using this option use the DOC provided for the Bulk Waste option for these uncharacterized waste streams as provided in 40 CFR 98.343(a)(2). A multivariate analysis of the facilities that use a hybrid approach of the Waste Composition option and the Bulk Waste option indicates that the optimal DOC value for uncharacterized MSW is much greater than the value for bulk DOC. The multivariate analysis indicates an optimal DOC value for uncharacterized DOC when using the waste composition option of 0.32. Therefore, we are proposing to include within Table HH-1 a DOC for uncharacterized MSW of 0.32 and proposing to revise 40 CFR 98.343(a)(2) to reference using this uncharacterized MSW DOC value rather than the bulk MSW value for waste materials that could not be specifically assigned to the streams listed in Table HH-1 for the Waste Composition option. Details of this analysis are available in the memorandum, Multivariate analysis of data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), Subpart HH (Municipal Solid Waste Landfills) to optimize DOC and k values, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
We note that DOC and k values are linked. Appropriate k values are primarily dependent on the composition of the waste and on the moisture content of the waste within the landfill (2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 5 Waste, Chapter 3), which is why subpart HH includes different k values based on annual precipitation rates. The multivariate analysis we conducted determined the optimal values for DOC and k values when varying both parameters. The optimal DOC value for bulk waste would have been higher if we had conducted a single variable analysis and had used only the k values currently provided in Table HH-1. Because of this linkage between the DOC and k values, the EPA is also proposing to revise the default decay rate values in Table HH-1 for both the Bulk Waste option and the Modified Bulk MSW option and add k value ranges for uncharacterized MSW for the Waste Composition Option as shown in Table 4 of this preamble. The proposed defaults represent the average optimal k values for the cohort of landfills within each precipitation category. The proposed k values are larger than the current defaults but provide a more accurate estimate of the landfill's emissions based on the results of the multivariate analysis. We also reviewed the k values used in other countries' inventories as well as those recommended in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories. We found that the current k values in Table HH-1 were low compared to those used in other countries with climates similar to that in the U.S. We also found that the k values we are proposing more closely align with those used in countries with similar climates to the U.S and with the defaults for moderately decaying bulk waste provided in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Because our review of other inventory k values and our multivariate analysis indicate that the current k values in Table HH1 are too low, we are proposing to revise these k values consistent with the results of our multivariate analysis and consistent with our revision to the default DOC for bulk waste.
Table 4. Proposed Default k Values
                                    Factor
                          Current Subpart HH Default
                          Proposed Subpart HH Default
                                     Units
k values for Bulk Waste option and Modified Bulk MSW option
k (precipitation plus recirculated leachate <20 inches/year)
                                     0.02
                                     0.055
                                    yr−1
k (precipitation plus recirculated leachate 20-40 inches/year)
                                     0.038
                                     0.111
                                    yr−1
k (precipitation plus recirculated leachate >40 inches/year)
                                     0.057
                                     0.142
                                    yr−1
k value range for Waste Composition option
k (uncharacterized MSW)
                                Not applicable
                                0.055 to 0.142
                                    yr−1

Altering both the default DOC and k values for subpart HH reporters would affect closed and open landfills in different ways. Implementing the recommended, and higher, k values will serve to increase the emissions calculated from Equation HH-1 and Equation HH-5 for open, active landfills. The higher k values imply that the organic material that is placed in the landfill will degrade more quickly than predicted when using lower k-values. This tends to lead to greater calculated emissions from active landfills (landfills actively receiving waste during a reporting year). The higher k values also tend to predict that less degradable waste will be in the landfill once the landfill closes (i.e., no longer receives wastes) and the degradable waste that is present in the closed landfill will decompose more quickly. This tends to reduce the emissions calculated for closed landfills, which may allow closed landfills to more quickly phase-out of the reporting program (i.e., when reported emissions fall below the 25,000 mtCO2e threshold for 5 years consecutive years). Thus, the proposed k values are expected to increase the calculated emissions from active landfills, reduce calculated emissions from closed landfills, and potentially reduce burden associated with the reporting requirements for closed landfills (due to having fewer years of reported emissions above the reporting threshold once the landfill is closed). We also note that the emissions from the landfill over its entire life (active and closed periods) is dependent only on the amount of degradable organic material placed in the landfill, which is dependent only on the DOC value. Thus, the lower DOC value should reduce the cumulative emissions reported for a given landfill over all reporting years; however, it may increase the emissions reported during the years the landfill is actively receiving wastes.
To determine an estimate of the effect of these changes on overall subpart HH emissions reporting, Equation HH-1 methane generation from six landfills in the final analysis cohort, three closed landfills (one in each precipitation range) and three open landfills (one in each precipitation range), were recalculated (as an illustrative example) with the recommended DOC value of 0.17 and the recommended k value corresponding to the landfill's precipitation zone. On average, the selected closed landfills had a 21 percent decrease in methane generation while the selected open landfills saw a 55 percent increase. These are illustrative examples and not a quantitative nationwide assessment of the impact of the proposed revisions to DOC and k values, but they confirm our expectations. The nationwide impact of these changes will likely be limited to a large extent because the large majority (approximately 90 percent) of the emissions reported under subpart HH are from facilities with GCS. Facilities with GCS use two different calculation methodologies to determine methane emissions: Equation HH-6, which used the predicted methane generation from Equation HH-1 and the amount of methane recovered, and Equation HH-8, which is based solely on the quantity of methane recovered. Per 40 CFR 98.346(i)(13), facilities with GCS may then choose the equation result that best represents emissions from the landfill to use as their total methane emissions reported for subpart HH. About 71 percent of subpart HH facilities in RY2020 used Equation HH-8 to estimate their methane emissions and the proposed revisions would not impact the emissions reported for these facilities. Thus, the proposed revisions would impact only the emissions from landfills without GCS and landfills with GCS that elect to report emissions using Equation HH-6, which is a smaller fraction (about 35 to 40 percent) of the total methane emissions reported subpart HH. While methane emissions reported by active landfills not using Equation HH-8 are expected to increase, the methane emissions reported by closed landfills are expected to decrease, and the total amount of methane reported to be generated by a given landfill over its entire life is expected to decrease (based on the proposed lower DOC value).
For the reasons described in section II.A.4 of this preamble, we are proposing a reporting requirement for landfills with gas collection and control systems to inform the development of GHG policies and programs by providing information on the proportion of landfill gas used in energy recovery projects. There is no anticipated significant change in burden due to this reporting requirement because key data in estimating the annual amount of recovered CH4 from data reported by measurement location and destruction device are already reported. Specifically, we are proposing to require landfills with gas collection and control systems to indicate the percentage of recovered CH4 that is sent to a flare or sent to a landfill gas to energy project for each measurement location.
For landfills with gas collection and control systems, we currently collect the following information under 40 CFR 98.346(i) related to the gas collection and control system at the facility: total volumetric flow of landfill gas collected for destruction, the annual average CH4 concentration of landfill gas for destruction, and an indication of whether destruction occurs at the landfill facility, off-site, or both. For landfills where destruction occurs at the facility, we also ask for information about the measurement location(s) and destruction device(s) at the facility. This information includes the number of destruction devices associated with each measurement location, the annual operating hours of each measurement location and its associated destruction devices, and the annual quantity of recovered CH4 using Equation HH-4 for each measurement location. We do not collect specific information about destruction devices located off-site and therefore cannot collect the annual quantity of CH4 recovered using Equation HH-4 at the destruction device level for all facilities subject to subpart HH. Therefore, we are proposing to collect information at the measurement location level about the proportion of landfill gas that is flared versus sent to a landfill gas to energy project. Specifically, we are proposing at 40 CFR 98.346(i)(6)(i) to require landfills with gas collection and control systems to indicate the percentage of recovered CH4 that is flared or sent to a landfill gas to energy project for each measurement location. We understand that a facility owner or operator may not know the exact quantity of recovered CH4 sent off-site for destruction by a flare or landfill gas to energy project. Facilities that indicate off-site destruction in e-GGRT and do not know whether the recovered gas sent to the off-site destruction device is sent to a flare or landfill gas to energy project would be allowed to allocate the off-site portion of recovered gas into an "unknown" option along with an optional text description.
This information would help inform the development of GHG policies and programs under the CAA by providing information on the amount of recovered CH4 that is beneficially used in energy recovery projects and will assist in verification of net CH4 emissions from landfills with gas collection and control systems. This new requirement will also assist with QA/QC of required inputs into the U.S. GHG inventory for MSW landfills and will inform EPA, state, and local government officials on progress towards renewable energy targets and GHG emission inventories. Additionally, researchers have requested this information under the U.S. national solid waste inventory. We are also proposing related confidentiality determinations for the new data element, as discussed in section VI of this preamble.
R. Subpart NN  --  Suppliers of Natural Gas and Natural Gas Liquids
For the reasons discussed in section II.B.3 of this preamble, the EPA is proposing to streamline reporting requirements by eliminating some duplicative reporting between subpart NN (Suppliers of Natural Gas and Natural Gas Liquids) and subpart W (Petroleum and Natural Gas Systems) by eliminating the duplicative elements from subpart W, as discussed in section III.J.2.f of this preamble.
S. Subpart OO  --  Suppliers of Industrial Greenhouse Gases