 TECHNICAL SUPPORT DOCUMENT FOR NON-FUEL ENERGY PURCHASES: SUPPLEMENTAL PROPOSED RULE FOR ADDING ENERGY CONSUMPTION SOURCE CATEGORY UNDER 40 CFR PART 98

                                       Office of Air and Radiation
                                 U.S. Environmental Protection Agency April 1, 2023

                                                 CONTENTS

 Source Description.
 Purchased electricity.
 Purchased, non-fuel, thermal energy products.
 Total Emissions.
 Review of Existing Programs and Methodologies.
 EPA Climate Leaders/The Climate Registry
 DOE 1605(b) Voluntary Reporting.
 The UK's Carbon Reduction Commitment.
 CARB requirements.
 State of Oregon.
 State of Washington.
 Type of Emissions Information that Could be Reported.
 Electricity purchase data.
 Thermal energy purchase data.
 Options for Reporting Threshold.
 Option 1: Do not require reporting of indirect emissions from any facilities.
 Option 2: Require otherwise subject GHGRP facilities to report energy purchases.
 Option 3: Require reporting of indirect emissions above a threshold value.
 Options for Monitoring Electricity Usage.
 Monitoring for Option 1.
 Electricity Monitoring Methods for Option 2.
 Electricity Monitoring Methods for Option 3.
 Thermal Energy Monitoring Methods under Options 2 and 3.
 Options for Estimating Missing Data.
 QA/QC Requirements.
 References.

 Source Description

  For stationary sources, non-fuel energy purchases include electricity and thermal energy products. In this technical support document (TSD) we refer broadly to purchased electricity and thermal energy products such as steam, heat (in the form of hot water), and cooling (in the form of chilled water) as "purchased energy" or as "purchased energy products." These terms expressly exclude fuel purchases associated with direct emissions that are currently reported under 40 CFR Part 98. Including energy consumption from purchased energy products in the Greenhouse Gas Reporting Program (GHGRP) would assist EPA to gain an improved understanding of the energy intensity (i.e., the amount of energy required to produce a given level of product or activity, both through onsite energy produced from fuel combustion and purchased energy) of specific facilities or sectors, and to better inform our understanding of energy needs and the potential indirect GHG emissions associated with certain sectors.

       Purchased Electricity. At industrial facilities, the most common form of purchased energy is electricity. The electric utilities that serve industrial consumers compose the largest emitting sector among stationary sources in the United States.  The level of GHG emissions associated with industrial electricity service is determined by the supplier's mix of generating technologies and by the customer's operational needs and purchased quantities. Including quantities of purchased electricity and associated suppliers in the GHGRP would provide data necessary to track changes in energy consumption with implementation of numerous local, state, and federal programs designed to improve energy efficiency and reduce the power sector's dependance on fossil-fuel technologies.

      Electric utility services are somewhat unique among major industrial transactions because electricity is a highly fungible product with an interconnected delivery system that crosses state and regional boundaries. These delivery systems virtually all terminate at electric meters on the property of the consumer. These attributes enable unique energy consumption monitoring strategies for electric services, and the expansive delivery system accommodates integration of a wide range of generating technologies, including an expanding network of renewable generating technologies. Many states continue to rely on these attributes to establish and expand renewable portfolio standards to increase capacity from renewables, including wind and solar plants with zero direct emissions. While wind and solar generating technologies are not directly subject to the GHGRP or to the EPA's emissions reduction programs under sections 110, 111, 112, or Title IV of the Clean Air Act (CAA), rapid growth in renewables has proven their viability for achieving CAA objectives by displacing fossil fuel-fired generators.

      Over the next thirty years, increased adoption of renewables in the power sector is expected to continue to displace fossil fuel-fired capacity. This trend has the potential to significantly decrease the environmental impacts of the electric services required at industrial facilities. Collection of the data elements necessary to track quantities of energy consumed and associated delivery systems would support CAA objectives under §§ 101(a)(3) and (4) by providing a national data resource that can be used to identify the most effective local, state, and federal programs for reducing energy consumption and associated environmental impacts. The "demand-side" data collections necessary to quantify the purchased energy consumption of industrial facilities would complement existing GHGRP data collection from direct emitters. With data on both direct emissions (that can be easily converted to fuel derived  energy use estimates) and purchased energy consumption for the largest industrial sources, the GHGRP, over time, could provide a more comprehensive quantitative record for identifying the most energy efficient facilities in each sector and any associated local, state, and federal programs.
      In addition to providing better insight on rapidly changing energy-use and emissions profiles and feedback on the effectiveness of existing programs, the collection of electricity purchase data would benefit a wide variety of future complementary GHG program design decisions. In many energy-intensive sectors, production metrics are used to help verify reported direct emissions. Including purchased electricity in the metrics from these sources provides more accurate product carbon intensity data, especially from industries where electricity and fuel use are equally critical. Purchased electricity data can be essential when determining performance benchmarks where energy-use must be normalized to a standard basis before comparing the performance of similar industrial processes with differing energy supplies.
      Finally, electric services within the energy consumption source category have been characterized by significant changes since 2007 when GHG emissions from the electric utility sector peaked. This document relies on emissions data for the utility sector available from the EPA's U.S. GHG Inventory site. This document relies on  electricity consumption data for residential, commercial, and industrial users from the Department of Energy's site for mandatory reporting by electric utilities under EIA Form 861. As discussed in Section 2 and presented in Tables 1, 2, and 3, GHG emissions from electric utilities have decreased by approximately 30 percent from the sector's 2007 peak. From 2007 to 2019, the number of industrial sources increased by 24 percent, but total electricity consumption increased by only 7 percent. The average electricity consumption by approximately 1 million industrial users in 2019 decreased by 13 percent compared to the average usage of 800,000 industrial customers in 2007. As these changes continue, including electricity purchases in the GHGRP will provide insight to policy makers on the industrial sectors with the most effective programs for optimizing the use of electricity. These data will allow the EPA to identify the best industry-specific operating practices and to evaluate options for expanding the use of these best practices.

       Purchased, Non-fuel, Thermal Energy Products. Many industrial facilities also purchase hot water, chilled water, or steam from adjacent, separately owned facilities. Like electricity usage data, including thermal energy purchases in the GHGRP would allow identification of best practices for industrial sources that require significant thermal energy. For example, one best practice involves an industrial facility contracting with an adjacent, separately owned combustion facility for steam delivery services. Often the steam suppliers deploy very efficient combined heat and power (CHP) technologies as depicted in Figure 1. These technologies can extract more energy from fossil fuels than conventional technologies.

       Just as data on electricity use is necessary for benchmarking and establishing best practices of energy use, data on thermal energy purchases is equally important. In order to compare the energy efficiency of two similar industrial operations, it is necessary to complete an energy balance for each of the two operations. In this respect purchased thermal energy in any form is no different than purchased electrical energy and the reporting of these purchases to the GHGRP would provide the data necessary to complete comparative efficiency analyses within each industrial sector.

      Figure 1. Schematic of combined heat and power (CHP) process (DOE, 2017) where a portion of the energy in fossil fuel is used to generate electricity and useful heat is extracted from the exhaust gases to also provide thermal energy products.

   Total Emissions (Based on Inventory) and Industrial Electricity Usage

     In 2009 when the EPA first considered including purchased electricity in the GHGRP, the latest U.S. GHG Inventory (for 2006) reported 2,328 million metric tons of CO2e (MMTCO2e) from the electric utility sector (USEPA, 2008). The CO2e emissions data in Table 1 is from the EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019 (USEPA, 2021). These data reflect the GHG emissions trend for electric utilities from 2015 to 2019. The lower four rows of Table 1 and all the data in Table 2 (related to the electricity consumption for residential, commercial, and industrial customers) reflects data reported to EIA Form 861 from 2015 to 2019.

     Table 1. U.S. electric power sector data for 2015-2019.

                                                                           2015

                                                                           2016
                                                                           2017
                                                                           2018
                                                                           2019
MMT CO2e Emissions
                                                                          1,900
                                                                          1,809
                                                                          1,732
                                                                          1,754
                                                                          1,606
Residential MWh
                                                                  1,500,274,917
                                                                  1,506,002,890
                                                                  1,471,508,108
                                                                  1,570,153,587
                                                                  1,544,640,471
Commercial MWh
                                                                  1,632,234,190
                                                                 1,642,425,590
                                                                  1,627,096,100
                                                                  1,666,736,129
                                                                  1,643,706,460
Industrial MWh
                                                                  1,167,903,485
                                                                  1,160,718,008
                                                                  1,171,090,558
                                                                  1,192,731,816
                                                                  1,192,834,602
Totals for All Customer Classes
                                                                  4,300,412,592
                                                                  4,309,146,488
                                                                  4,269,694,766
                                                                  4,429,621,532
                                                                  4,381,181,533

     Table 2 shows the usage by customer classes for 2019 and Table 3 shows the usage by customer class during the year with the highest GHG emissions from the electric utility sector (2007). Comparison of Table 2 to Table 3 indicates that GHG emissions from electric utilities in 2019 were 31 percent lower than peak annual emissions while serving 17 percent more customers, with all customer classes in 2019 showing lower usage per customer compared to the 2007 peak emissions year.

     Table 2 indicates that the average industrial customer uses two orders of magnitude more electricity than the average residential customer and more than an order of magnitude more electricity than the average commercial customer. This high usage per industrial customer demonstrates the high value of industrial energy use data for identifying changes in demand patterns and assessing the effectiveness of demand-side management programs.

     Table 2. U.S. electric power sector usage by customer class in 2019 with sector-wide emissions of 1,606 million metric tons CO2e
Customer Class
                               2019 Usage (MWh)
                                Customer Count
                                 MWh/Customer
Residential
                                 1,544,640,471
                                                                    148,076,510
                                     10.4
Commercial
                                 1,643,706,460
                                                                     21,021,398
                                     78.2
Industrial
                                 1,192,834,602
                                                                      1,004,001
                                    1,188.1
Total for All Customer Classes
                                 4,381,181,533
                                                                    170,101,909
                                     25.8

     Table 3. U.S. electric power sector usage by customer class in 2007 with sector-wide emissions of 2,411 million metric tons CO2e (U.S. historic peak for sector).
Customer Class
                               2007 Usage (MWh)
                                Customer Count
                                 MWh/Customer
Residential
                                 1,408,591,211
                                                                    126,046,493
                                     11.2
Commercial
                                 1,493,849,690
                                                                     17,988,627
                                     83.0
Industrial
                                 1,114,527,346
                                                                        812,039
                                    1,372.5
Total for All Customer Classes
                                 4,016,968,247
                                                                    144,847,159
                                     27.7

     Figure 2 below indicates that total industrial electricity usage has significantly increased in recent years while total emissions from electricity providers have significantly decreased. Nationally, this is largely due to the relatively low price of natural gas compared to coal during this period, the lower carbon content of natural gas compared to coal, availability of significantly more efficient generating technologies for natural gas (i.e., combined cycle power blocks) compared to coal, and, increased deployment of wind and solar generating technologies.

     Tables 1, 2, 3 above and Figure 2 below indicate how energy sector emissions and industrial energy usage patterns can rapidly change over a relatively short time. Including purchased energy data in the GHGRP data would assist assessments of the relative contributions of supply- vs. demand-side changes.

     Figure 2. Comparison of industrial usage of electricity to emissions from the electricity sector from 2015 to 2019.

   Review of Existing Programs and Methodologies

   Some existing programs refer to GHG emissions from fossil fuel-fired electric and thermal energy service providers as "indirect emissions" attributable to the purchaser's operations. These programs require the purchaser to report indirect emissions based on the GHG protocol established by the World Resources Institute and World Business Council for Sustainable Development (WRI/WBCSD). Other reporting programs require only the reporting of energy purchases and sales. Data on electricity and thermal energy purchases, sales and use are typically readily available to large companies.

        EPA Climate Leaders/The Climate Registry/California Climate Action Registry programs all use EPA Emissions & Generation Resource Integrated Database (eGRID) data to calculate GHG emissions from electricity use. Transmission and Distribution (T&D) losses are assigned to T&D companies. Emissions from multiple facilities may be reported together at the corporate level or reported at the facility level.

        The Department of Energy (DOE) 1605(b) Voluntary Reporting of Greenhouse Gas Emissions Program uses state-based Energy Information Administration (EIA) factors that include T&D losses to calculate GHG emissions from electricity use.

        The United Kingdom's Carbon Reduction Commitment (CRC) program uses a single national grid emission factor for all electricity usage.

        California Air Resources Board (CARB) requires industrial facilities to report "facility-level energy input and output." This includes the reporting of all purchases and sales of either electricity or thermal energy. Respondents must report the electricity transacted in megawatt-hours (MWh) with the name and program identifier of the counterparty to the transaction. For thermal energy transactions the respondent must report the quantity in million Btus (MMBtu), the name of the counterparty, and the program identifier of the counterparty.

        The State of Oregon does not require the customers of electric utilities to report electricity consumption. However, Oregon does require their electric utilities to report both emissions and electricity sales. Oregon uses the emissions and generation data to develop utility-company-specific emission factors for the utilities operating in the State.

        The State of Washington does not require the reporting of thermal energy products but does require the reporting of "total annual electricity purchased in megawatt hours (MWh), itemized by the supplying utility or electric power entity for each different source of electricity." Washington also requires reporting of self-generated electricity.

     Type of Emissions Information that Could be Reported

   Considering the design of current GHG emissions reporting programs with respect to purchased energy consumption data, the following information could be reported:

        Electricity purchase data.

             The state and locality of the purchased electricity meter.
             Meter-specific purchased electricity quantity in kilowatt hour (kWh) as reported on each periodic billing statement.
             The name and zip code of the electric utility delivery service provider, and if applicable (in unregulated markets), the name of the electric utility supply company.
             A copy of 1 typical monthly, quarterly, or annual (as applicable) billing statement for each electric utility service company (and rate category) that served the facility during the reporting year.
             The meter number (from the periodic billing statements) associated with each reported quantity of electricity used.
             Annual sequence of bill. This is a number from 1 to 12 for monthly billing cycles, from 1 to 4 for quarterly billing cycles, and from 1 to 2 for semi-annual billing cycles.
             The start date and end date of the electricity usage period for each reported quantity of electricity used.
             The rate descriptor for each usage period as presented on the billing statement (e.g., Large General Service-Curtailable Time-of-Use/LGS-CUR-TOU).
             See Table 8-1 for an example reporting format for these data.

        Thermal energy purchase data.

             Facility-level purchased thermal energy quantity in standard units, such as million British thermal units (MMBtu),
             The name of the thermal energy supplier (as it appears on periodic billing statements) and the public GHGRP facility identifier of the thermal energy supplier or the suppliers zip code if the supplier does not report to the GHGRP.
             A copy of 1 typical monthly, quarterly, or annual (as applicable) billing statement for each thermal energy supplier that served the facility during the reporting year.
             The meter number (from the periodic billing statements) associated with each reported quantity of thermal energy purchased.
             The start date and end date of the billing period for each reported quantity of thermal energy purchased.
             The rate descriptor for each billing period as presented on the billing statement.
             See Table 8-2 for an example reporting format for these data.

   Options for Reporting Threshold

   The following options were considered for the reporting of purchased electricity and thermal energy products:

        Option 1:  Do not require the reporting of purchased electricity and thermal energy products from any facility.

        Option 2: Require reporting of electricity and thermal energy purchases only from direct emitting facilities that meet the current applicability requirements under 40 CFR Part 98.2 as amended on December 9, 2016. No additional facilities would become subject to the GHGRP under this option. For RY2021 7,587 facilities reported to the GHGRP under the contemporaneous applicability requirements.

        Option 3: Require reporting of purchased electricity and thermal energy products by all facilities where annual facility CO2-equivalent emissions from indirect emissions combined with the emissions from the facility's direct emission sources exceed one of the following thresholds:

             CO2-equivalent facility-wide emissions of 100,000 tons or more (approximately 2,850 facilities affected within the current GHGRP reporting population).
             CO2-equivalent facility-wide emissions of 25,000 tons or more (approximately 11,850 facilities affected including approximately 6,450 current GHGRP reporting facilities).
             CO2-equivalent facility-wide emissions of 10,000 tons or more (approximately 49,850 facilities affected including 7,050 current GHGRP reporting facilities).
             CO2-equivalent facility-wide emissions of 1,000 tons or more (approximately 74,850 facilities affected including 7,350 current GHGRP reporting facilities).

   The estimated number of affected facilities for Option 3 above is derived from the 2018 US Census Bureau's Business Dynamics Statistics (BDS) survey, GHGRP emissions data for RY2018, and the most recent (2018) Manufacturing Energy Consumption Survey (MECS) under the Department of Energy's mandatory EIA Form 846 reporting program. The BDS survey indicates that there were more than 7 million businesses in the United States in 2018. The survey divides those businesses into 19 sectors based on North American Industry Classification System (NAICS) codes. Facilities from all 19 of these NAICS codes have reported to the GHGRP since 2010.

   Estimates of the number of affected facilities were developed using the following steps:

      Step 1. Used GHGRP data to characterize the distribution of facility-level direct emissions among the population of reporters with the lowest annual emissions. Figures 3.1 and 3.2 present a typical distribution as reflected by the set of GHGRP reporters from 2010 to 2020 under NAICS Code 21 Mining, Quarrying, and Oil and Gas Extraction characterized by a linear tail near the lower end of the distribution. Subsequently, linear models were developed to represent the distribution of facility-level emissions for applicability analyses of facilities operating near various applicability thresholds. Facilities reporting zero emissions to the GHGRP were not included in the distributions.

      Figure 3.1 Typical distribution of annual emissions from stationary sources as reported to the GHGRP and sorted highest to lowest.

      Figure 3.2 Lower end only of typical distribution of annual GHGRP emissions from stationary sources sorted highest to lowest.

      Step 2. The slope of the linear model for each industrial sector was developed using the following data sources:

 US Census Bureau from the Business Dynamics Statistics (BDS) survey defining the number of establishments within each 2-digit NAICS code sector.
 The portion of the GHG National Inventory for electricity, industrial and commercial sources. In 2018, the Inventory reported total emissions from these sectors of 3,729 MMT CO2e. The linear model was constrained so that integrals of sector-specific linear functions (for the 2018 non-GHGRP reporters) added to the 2018 GHGRP inventory equaled 3,729 MMTCO2e.
 The GHGRP emissions data for RY2018 as reported by all facilities within the 19 two-digit NAICS codes in the BDS.
 EIA Form 846 data for the manufacturing sectors (NAICS 31-33)
 EIA Form 861 data for electricity consumption in the industrial and commercial macro sectors.

      Step 3. A synthetic population of reporters was developed for each industrial sector. Each sector-specific population had the following attributes:

 The number of establishments in the US Census BDS (2018).
 The number of GHGRP reporters in RY2018.
 The total emissions reported to the GHGRP for the sector for RY2018.
 The estimated portion of the population with zero direct emissions (i.e., electricity-only facilities).
 An estimated upper bound of the annual direct emissions from the largest facilities operating below the RY2018 GHGRP reporting thresholds.
 The number of employees per establishment based on US Census BDS data.
 The average electricity use per employee based on EIA Form 846 data, US Census BDS data, and the total national, commercial and industrial electricity usage in 2018.

      Step 4. The synthetic populations of establishments were used in an aggregated form to develop sector-specific (two-digit NAICS) estimates consistent with the National GHG inventory when added together.

      Step 5. The synthetic populations were then used in a disaggregated form to assess facility-level direct emissions and facility-level indirect emissions from electricity usage only. Estimates of thermal energy purchases were not developed with the synthetic populations because EIA Form 846, indicates that energy in the form of steam represented less than 5 percent of the energy usage by the manufacturing sector (NAICS codes 31-33), and no data were identified for estimating the thermal energy purchases for the eighteen other sectors. Accordingly, parameters for estimating thermal energy purchases were not included in the synthetic population.

      Step 6. The facility-level synthetic populations were compared to each of the reporting thresholds considered under Option 3 to determine the number of affected facilities, the associated indirect emissions, and the associated direct emissions that would be included in the GHGRP under each threshold.

  Table 4-1 presents the results of the synthetic population analyses for the sectors included in NAICS codes 11-81.

  Table 4-2 presents a more detailed view of some of the 2-digit NAICS sectors with the GHGRP facility counts, the 2018 GHGRP emissions, and the US Census BDS establishment counts for 2018.

  Table 5 presents the electricity usage per employee based on EIA 846 data and US Census employee counts by sector. For each NAICS code in Table 5, the total electricity usage reported under EIA Form 846 was divided by the total, national employee population reported for the NAICS code from the US Census BDS survey.

  Table 4-1. Screening of GHGRP Applicability Impacts with Indirect Emissions.

 Sectors
 Annual Threshold
 National
 Direct Emissions
 National
 Indirect Emissions
 US Census Facilities in BDS (2018)
                               Emissions Covered
                              at Threshold Level
                            Establishments Covered

                                    MT CO2e
                                   MMT CO2e
                                   MMT CO2e
                                     Count
                               Percent of Direct
                              Percent of Indirect
                                     Count
                                                                        Percent

 NAICS
 11-81
   >1,000
                                                                          3,729
                                                                          1,790
                                                                      7,073,239
                                                                          90.3%
                                         29.8%
                                                                         74,850
                                                                          1.06%

   >10,000
                                                                          3,729
                                                                          1,790
                                                                      7,073,239
                                                                          84.8%
    14.7%
                                                                         49,850
                                                                         0.71%

   >25,000
                                                                          3,729
                                                                          1,790
                                                                      7,073,239
                                                                          80.2%
      7.5%
                                                                         11,850
                                                                          0.17%

  >100,000
                                                                          3,729
                                                                          1,790
                                                                      7,073,239
                                                                          75.7%
                                                                           4.3%
                                                                          2,850
                                                                          0.04%

Table 4-2 Summary of Sectors Included in 2018 US Census Business Dynamics Statistics (BDS) survey and the 2018 GHGRP  data set.

  Table 5. Electricity use per employee based on EIA MECS data and USCB BDS data.

NAICS
Description of Manufacturing Sector
Electric MWh / Employee
Electric MT CO2e / Employee
(indirect)
                                                                           3311
Iron and Steel Mills and Ferroalloys
                                                                        624.58
                                                                        269.94
                                                                            324
Petroleum and Coal Products
                                                                        509.53
                                                                        220.22
                                                                           3241
Petroleum Refineries
                                                                        469.10
                                                                        202.74
                                                                           3313
Alumina and Aluminum
                                                                        438.14
                                                                        189.36
                                                                            331
Primary Metals
                                                                        303.71
                                                                        131.27
                                                                           3112
Grain and Oilseed Milling
                                                                        248.13
                                                                        107.24
                                                                           3314
Nonferrous Metals, except Aluminum
                                                                        228.74
                                                                         98.86
                                                                           3252
Plastics Materials and Resins
                                                                        227.56
                                                                         98.35
                                                                            325
Chemicals
                                                                        197.91
                                                                         85.54
                                                                           3221
Paperboard Mills
                                                                        186.83
                                                                         80.75
                                                                           3251
Other Basic Inorganic Chemicals
                                                                        185.15
                                                                         80.02
                                                                           3221
Paper Mills, except Newsprint
                                                                        181.62
                                                                         78.49
                                                                            322
Paper
                                                                        163.71
                                                                         70.75
                                                                           3253
Nitrogenous Fertilizers
                                                                        160.67
                                                                         69.44
                                                                           3251
Industrial Gases
                                                                        146.36
                                                                         63.26
                                                                           3312
Steel Products from Purchased Steel
                                                                        139.27
                                                                         60.19
                                                                           3314
Nonferrous Metal (except Aluminum) Smelting/Refining
                                                                        135.93
                                                                         58.75
                                                                           3251
Other Basic Organic Chemicals
                                                                        135.31
                                                                         58.48
                                                                           3122
Tobacco
                                                                        122.11
                                                                         52.78
                                                                            313
Textile Mills
                                                                        116.62
                                                                         50.41
                                                                           3274
Gypsum
                                                                        107.91
                                                                         46.64
                                                                           3112
Wet Corn Milling
                                                                        101.94
                                                                         44.06
                                                                           3274
Lime
                                                                         97.89
                                                                         42.31
                                                                            327
Nonmetallic Mineral Products
                                                                         94.71
                                                                         40.93
                                                                           3315
Foundries
                                                                         92.98
                                                                         40.19
                                                                           3313
Aluminum Sheet, Plate and Foils
                                                                         89.71
                                                                         38.77
                                                                           3211
Sawmills
                                                                         87.85
                                                                         37.97
                                                                           3212
Veneer, Plywood, and Engineered Woods
                                                                         87.65
                                                                         37.88
                                                                           3115
Dairy Product
                                                                         77.32
                                                                         33.42
                                                                           3251
Ethyl Alcohol
                                                                         68.70
                                                                         29.69
                                                                           3273
Cements
                                                                         65.58
                                                                         28.34
                                                                           3253
Phosphatic Fertilizers
                                                                         65.21
                                                                         28.18
                                                                            326
Plastics and Rubber Products
                                                                         62.94
                                                                         27.20
                                                                           3114
Fruit and Vegetable Preserving and Specialty Food
                                                                         62.51
                                                                         27.02
                                                                            312
Beverage and Tobacco Products
                                                                         60.62
                                                                         26.20
                                                                           3116
Animal Slaughtering and Processing
                                                                         60.57
                                                                         26.18
                                                                            311
Food
                                                                         58.99
                                                                         25.49
                                                                           3121
Beverages
                                                                         58.92
                                                                         25.47
                                                                           3212
Reconstituted Wood Products
                                                                         55.15
                                                                         23.83
    5.3 Option 3: (continued)

      To estimate impacts under Option 3, sector-specific, facility-level metrics proportionate to electricity usage were required to develop facility-level estimates for combined indirect and direct emissions. Electricity usage estimates were based on the US Census BDS survey's establishment counts (i.e., facility counts) and the following seven establishment-employee-size categories:
(a) Establishments with 1-4 employees
(b) Establishments with 5-9 employees
(c) Establishments with 10-19 employees
(d) Establishments with 20-99 employees
(e) Establishments with 100-499 employees
(f) Establishments with 500-999 employees
(g) Establishments with 1000+ employees
Table 6 presents typical BDS data sets for NAICS Code 21  -  Mining, Quarrying, and Oil and Gas Extraction and aggregated codes 31 to 33  -  Manufacturing. The BDS provided 19 data sets similar to the sets in Table 6 that were used to develop the facility-level estimates for each of the 19 sectors included in the Option 3 impacts analysis. According to the BDS glossary, a firm is analogous to a corporation like ExxonMobil. An establishment is analogous to an operating facility like an automotive service station. The BDS also has 4-digit NAICS code data as presented in Table 7, however the 4-digit data sets do not include establishment-sizes.

Table 6. Example US Census Bureau BDS, 2-digit NAICS, sector-level data sets used to develop facility-level estimates of electricity consumption.

Table 7. Example US Census Bureau BDS, 4-digit NAICS, sector-level data sets used together with EIA Form 846 data to develop facility-level estimates of electricity consumption for the manufacturing sector (NAICS Codes 3111-3399).

The first step in developing facility-level electricity consumption estimates was to use the BDS 4-digit NAICS data sets (like the examples in Table 7) together with 3-to-6-digit NAICS data published under EIA Form 846 to develop MWh per employee factors as shown in Table 5. Subsequently, these factors were combined into a weighted average factor for the 31-33 NAICS category in Table 6 with each factor given the weight of the NAICS4-specific total electricity consumption (from EIA 846) divided by the total electricity consumption for NAICS 31-33 (also from EIA 846).

For facilities in non-manufacturing sectors, an average factor of 14.67 MWh per employee was used. This factor was back calculated from the 2018 total electricity consumption reported under EIA Form 861 for industrial and commercial customers: 2,859 million MWh. First the electricity consumption for the manufacturing sector (from EIA Form 846 data) was subtracted from the EIA 861 total industrial and commercial electricity usage. The remaining EIA 861 electricity consumption was divided by the total number of non-manufacturing sector employees. The synthetic populations used to estimate the numbers of facilities that would be affected under the reporting options presented in Table 4-1 are included in the docket as Excel workbooks. Sector-wide estimates of electricity consumption were converted to estimates of indirect emissions estimates using the average national emission factor from EPA's eGRID data set (0.4322 MT CO2e/MWh).
 Options for Purchased Energy Monitoring Methods

  The following monitoring methods were evaluated for each of the possible reporting threshold options.

 Monitoring and Recordkeeping for Option 1

  There are no monitoring requirements for Option 1.
 Energy Monitoring Methods and Recordkeeping for Option 2

           Metered Energy Monitoring Plan (MEMP). Owners and operators would be required to develop a written MEMP for purchased energy that specifies recordkeeping activities at the same frequency as billing statements. Operators would also be required to document in the MEMP and implement QA/QC requirements to ensure that the records collected for the annual reporting requirement are consistent with their monthly, quarterly, or semi-annual (as appliable) billing statements. At a minimum, the MEMP would include the elements listed in this paragraph and in section 6.4 where additional elements for thermal energy monitoring and recordkeeping are described.

                  Identification of positions of responsibility (i.e., job titles) for collection of the energy consumption data.
                  The identifier(s) of the meter(s) used on periodic billing statements for electricity or in purchasing agreements for thermal energy with a one or two sentence description of the portions of the facility served by each meter.
                  For each meter an indication of the billing frequency (e.g., monthly, quarterly, semi-annually, etc.)
                  A copy of one typical billing statement that includes all pages for each meter with the meter identifier, the name of the delivery service provider, the name of the supply service provider (if applicable in deregulated states), the dates of service, the usage in kWh or MWh for electricity, the usage in million British thermal units (MMBtu) for thermal energy, and the rate descriptor.
                  A digital image or photograph of each meter bearing the identifier of the meter on the periodic electricity billing statements or bearing the identifier or description in the purchasing agreement on thermal energy billing statements. If possible, the manufacturer's name, and model number would also be visible in the image
                  For electric meters, an indication of whether the meter complies with ANSI C12.1-2022: Electric Meters - Code for Electricity Metering. The purchasing facility's owner or operator would be required to document in the monitoring plan the outcome of the owner or operator's inquiries seeking to determine whether the electric meters in service at the facility comply with ANSI C12.1-2022.
                  For thermal energy meters the purchasing facility would also follow specific requirements for thermal energy monitoring as delineated in section 6.4.
                  For both electrical and thermal energy meters, an explanation of the processes and methods used to collect the necessary data to report the total annual usage of purchased electricity in kWh and the total annual usage of thermal energy products in MMBtu. For thermal energy products the plan must include a clear explanation and example of how data measurements are converted to MMBtu.
                  For both electrical and thermal energy meters, descriptions of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to collect the energy consumption data reported under this part. Section 6.4 includes additional requirements for quality assurance that are specific to thermal energy monitoring systems.
                  For both electrical and thermal energy meters, the MEMP could rely on references to existing corporate documents (e.g., purchasing agreements, standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that required elements are easily recognizable.
                  The owner or operator would be required to revise the MEMP as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.

           If requested by the Administrator, owners or operators would be required to make all information collected in conformance with the MEMP (under paragraphs <IP_ADDRESS>-<IP_ADDRESS> and paragraph 6.4) available for review. Electronic storage of the information in the plan would be permissible, provided hard copies could be made available, upon request.

           Required recordkeeping for annual reporting. The owner or operator would be required to maintain records of the following data elements and to report these data elements annually.

                  State of electric or thermal energy service location (i.e., electric meter or thermal energy meter location).
                  Locality (County) of service location. The state and county would be used to provide the reporter with a lookup list of the electric utilities providing service to customers in the county. This would ensure consistency of the utility names reported and would minimize the burden of entry for reporting purchased electricity. For localities not located in a county, such as Alexandria, Virginia, reporters would provide the city. The most recently published data from EIA Form 861 could be used to provide a listing of electric utility service providers by locality. This requirement would also apply to purchased thermal energy.
                  Energy delivery provider. The name of the utility to whom the purchaser will send payment for electricity service or the name of the counterparty in thermal energy purchasing agreements.
                  Identifying number for energy delivery service provider:
 For purchased electricity, the zip code of the electric utility to whom the purchaser will send payment.
 For purchased thermal energy, the public GHGRP facility identifier of the supplier, or if the supplier does not report to the GHGRP, the zip code of the physical location of associated thermal energy production systems.
                  Energy supply service provider. This reporting requirement would only apply to purchased electricity in deregulated states. In addition to the energy delivery provider under <IP_ADDRESS>, facilities would be required to report the name of the electric utility that actually produced the purchased electricity. In deregulated states, electricity billing statements typically separate energy supply services and energy delivery services. Energy delivery services are associated with the electric meter, service connections, transformers, poles, and wires necessary to connect the customer to the grid. Energy supply services are associated with the power plants and fuel charges for production of the purchased electricity. In deregulated states, billing statements may identify one utility company as the energy delivery service provider and a different utility company as the energy supply service provider.
                  Meter number. For electricity service, each billing statement commonly includes an alpha numeric identifier for the electric meter associated with the usage on the billing statement. The meter number would be reported for each quantity of electricity purchased and itemized on periodic billing statements.
                 For thermal energy, the meter identifier from the purchasing agreement would be used. For thermal energy purchasing agreements that do not include a meter identifier, the serial number of the meter, the model number of the meter, or the description of the meter in the purchasing agreement could be used.
                  Annual sequence of bill. A number typically ranging from 1 to 12 for monthly billing cycles, from 1 to 4 for quarterly billing cycles, and from 1 to 2 for semi-annual billing cycles. For billing cycles that include changes to the rate plan, additional sequence numbers may be necessary to log all the discrete quantities of energy purchased during the reporting period.
                  Start date of period billed. The date designating when the usage period began for each billing statement. For monthly billing cycles, the annual report would typically include 12 start dates. For quarterly billing cycles the annual report would typically include 4 start dates. For semi-annual billing cycles the annual report would typically include 2 start dates. For billing cycles that include changes to the rate plan, additional start dates may be necessary.
                  End date of period billed. The date designating when the usage period ends for each billing statement. For monthly billing cycles, the annual report would typically include 12 end dates. For quarterly billing cycles the annual report would typically include 4 end dates. For semi-annual billing cycles the annual report would typically include 2 end dates. For billing cycles that include changes to the rate plan, additional end dates may be necessary.
                  Quantities of purchased electricity and thermal energy products:
                       For purchased electricity, facilities would report the kilowatt-hours (kWh) used for each meter listed on each billing statement with service during the reporting period. For each meter on each electric bill received during the reporting period, the usage should be clearly designated. This value may be listed on the billing statement in megawatt-hours (MWh). To convert billing statements that report usage in MWh to kWh, the MWh value would be multiplied by 1000.
                       For purchased thermal energy, the value on the billing statement would be converted to million British thermal units (MMBtu) using standard engineering conversion factors and calculations as documented in the MEMP.
                 If the periodic billing statement spans two reporting years, reporters would allocate to each reporting year the portion of purchased electricity or thermal energy based on the number of days of service during each year or based on operational knowledge of the industrial processes for which energy is purchased. Facilities would be allowed to exclude any electricity that is generated outside the facility and delivered into the facility with final destination and usage outside of the facility. Facilities would also be allowed to exclude electricity consumed by operations or activities that do not support any activities reporting direct emissions under 40 CFR Part 98. Excluded quantities could be estimated based on company records or engineering judgment.
                  Rate Descriptor. Each electric bill should have a statement that describes the rate plan in effect for the billing location. This rate plan code can indicate if the customer is billed based on  time-of-use rates or if the customer is purchasing a renewable energy product. For example, a typical rate statement could be "Your current rate is Large Commercial Time of Use (LC-TOUD)." In this case the GHGRP reporter would enter "LC-TOUD" as the rate descriptor for the associated billing period.
                  Subpart-specific energy usage. Facilities subject to multiple direct emitting part 98 subparts would report the decimal fraction of purchased electricity or thermal energy products attributable to each subpart. The fraction could be estimated based on company records or engineering judgment.
                  Copy of one billing statement per energy service provider. The first annual report under subpart B would include an electronic copy of all pages of one billing statement received by the facility from each energy service provider of purchased electricity or thermal energy products. If the facility were to change or add one or more energy service providers after the first reporting year under subpart B, the annual report would include an electronic copy of all pages of one billing statement received from each new energy delivery service provider for only the first GHGRP reporting year of each new purchasing agreement. The file format of electronic copies of billing statements (e.g., pdf, jpeg, gif, tiff, or bmp) would be specified by the EPA in the reporting instructions published for each reporting year.

  Table 8-1. Example reporting form for electricity purchases.

State of Service Location
North Carolina
County of Service Location
Wake
Energy Delivery Service Provider Name
Duke Energy Progress
Energy Delivery Service Provider Zip Code
28201-1090
Energy Supply Service Provider
The energy supply company is typically the same as the energy delivery company in states with regulated utilities, but in states with deregulated utilities the energy supply company may be listed separately with separate charges on the billing statement.
Duke Energy Progress
Meter Number
Annual  Bill Sequence
Start Date of  Period Billed
End Date of Period Billed
kWH Used
Rate Descriptor
TU0199
1
12/25/2020
01/24/2021
8,820
C-TOUD
TU0199
2
01/25/2021
02/24/2021
8,320
C-TOUD
TU0199
3
02/25/2021
03/24/2021
7,770
C-TOUD
TU0199
4
03/25/2021
04/24/2021
7,840
C-TOUD
TU0199
5
04/25/2021
05/24/2021
8,850
C-TOUD
TU0199
6
05/25/2021
06/24/2021
9,220
C-TOUD
TU0199
7
06/25/2021
07/24/2021
9,420
C-TOUD
TU0199
8
07/25/2021
08/24/2021
8,570
C-TOUD
TU0199
9
08/25/2021
09/24/2021
7,720
C-TOUD
TU0199
10
09/25/2021
10/24/2021
7,890
C-TOUD
TU0199
11
10/25/2021
11/24/2021
8,410
C-TOUD
TU0199
12
11/25/2021
12/24/2021
9,130
C-TOUD

 Energy Monitoring Methods for Option 3

  The monitoring methods for this option are the same as provided above for Option 2. However, in addition to the monitoring methods of Option 2, facilities would be required to determine applicability by calculating their indirect emissions from purchased energy usage. Indirect emissions would be calculated using default emission factors for the mass of CO2, CH4 and N2O per MWh of electricity usage and per MMBtu of thermal energy usage. Default emission factors would be based on average emission rates that best represent the electricity or thermal energy actually purchased.  For electricity, the U.S. Environmental Protection Agency's Emissions & Generation Resource Integrated Database (eGRID) provides default emission rates in varying levels of detail including by generating company, balancing area, state, North American Electric Reliability Council (NERC) region, and U.S. average.
  Calculations of indirect emissions from electricity usage would follow the general equation:
                  	ECO2e = Σ(EFi * Electricity Purchases)
                  Where:
                  ECO2e 	= Emissions of CO2e
                  EFi 	= Emissions factors for CO2, CH4 and N2O from eGRID.

  Calculations of indirect emissions from fossil-fuel-derived thermal energy purchases would be derived from existing GHGRP data for the supplying facility or using the appropriate methodologies under 40 CFR Part 98 subpart C.

  Table 8-2. Example reporting form for thermal energy purchases.

State of Service Location
North Carolina
County of Service Location
Brunswick
City of Service Location
Southport
Thermal Energy Supplier Name
Capital Power
Thermal Energy Supplier Address*
1281 Powerhouse Drive
Thermal Energy Supplier Zip Code*
28461
Thermal Energy Supplier's Public GHGRP Identifier
Public GHGRP Identifiers are seven-digit numbers from 1000001 to 1020000.

1000225
Meter Number
Annual  Sequence of Bill
Start Date of  Period Billed
End Date of Period Billed
MMBtu   Purchased
Rate Descriptor
ADM101
1
12/25/2020
01/24/2021
88,200
ADM2021
ADM101
2
01/25/2021
02/24/2021
98,320
ADM2021
ADM101
3
02/25/2021
03/24/2021
97,770
ADM2021
ADM101
4
03/25/2021
04/24/2021
87,840
ADM2021
ADM101
5
04/25/2021
05/24/2021
88,850
ADM2021
ADM101
6
05/25/2021
06/24/2021
89,220
ADM2021
ADM101
7
06/25/2021
07/24/2021
89,420
ADM2021
ADM101
8
07/25/2021
08/24/2021
88,570
ADM2021
ADM101
9
08/25/2021
09/24/2021
78,720
ADM2021
ADM101
10
09/25/2021
10/24/2021
77,890
ADM2021
ADM101
11
10/25/2021
11/24/2021
89,410
ADM2021
ADM101
12
11/25/2021
12/24/2021
91,130
ADM2021
*Item is only required if no Public GHGRP Identifier is provided for the supplier.

 Thermal Energy Monitoring Methods and Recordkeeping under Options 2 and 3.

  The monitoring methods for thermal energy assume that purchasers of steam, hot water, or chilled water are counterparties to contracts that define how the thermal energy is metered and billed. The monitoring methods for the GHGRP would allow utilization of the methodologies in existing thermal energy purchasing contracts. Purchasers of thermal energy products would be required to report the information specified for thermal energy monitoring and recordkeeping in section 6.2.

 Options for Estimating Missing Data

  For both electricity and thermal energy purchases, reporters with missing billing statements would be required to request replacement copies of those statements from their local utility or thermal energy supplier. However, in the event that the electric utility or the thermal energy supplier is unable to provide replacement copies of billing statements, the facility could estimate electricity usage for the missing data period based on historical data (i.e., previous electricity purchase records). If a facility is using electric meter data and has a missing data period, the facility would estimate purchased electricity based on electricity provider records and historical meter data. Any historical data used to estimate missing data should represent similar circumstances to the period over which data are missing (e.g., from the same season).

 QA/QC Requirements
Facilities would be required to conduct quality assurance and quality control (QA/QC) for electricity and thermal energy usage, metering. and billing records to ensure that these records reflect actual energy consumption . Facilities would be required to include in their MEMP the steps necessary to ensure the meters used for electricity and thermal energy monitoring meet the minimum accuracy requirements and to validate all calculations supporting the annual report. Specific QA/QC requirements for electricity and thermal energy are included in this section.
 Quality assurance for electricity monitoring.
   The purchasing facility's owner or operator would be required to determine if the electric meter complies with ANSI C12.1-2022: Electric Meters - Code for Electricity Metering using one of the methods under paragraphs 8.1.1 to 8.1.3.
       The purchasing facility's owner or operator could identify the manufacturer and model number of the meter and obtain a copy of the meter's technical reference guide or technical data sheet indicating the meter's conformance to ANSI C12.1-2022. The owner or operator could include in the MEMP a copy of the technical data from the manufacturer indicating compliance with ANSI C12.1-2022.
       The purchasing facility could obtain a certification from the utility company that owns the meter indicating compliance with ANSI C12.1-2022.
       The purchasing facility would also be required to submit a request to their local utility to install an ANSI C12.1-2022 compliant meter as soon as practically possible if the owner or operator determines that any meter in service at the facility does not comply with ANSI C12.1-2022. Under this requirement, the owner of operator would be required to document in the MEMP all correspondence with the electric utility that owns the meter.
 Quality assurance for thermal energy monitoring.
       Requirements thermal energy meters assume that the purchasing facility is a counterparty to a purchasing agreement or purchase contract that defines the quality parameters that must be tracked and verified to ensure the accuracy of usage and billing records. The purchaser would be required to contact the supplier of each energy product and request a copy of the most recent audit of the accuracy of the metering system referenced in the purchasing agreement or purchase contract. If an audit of the metering system has never been completed or if the audit is more than five years old, the purchaser would be required to request that the supplier complete an energy audit consistent with the terms of the purchase contract. If the purchase contract does not include provisions for periodic audits of the metering system, the purchaser would be required to complete an audit of the metering system using a qualified metering specialist with knowledge of the associated thermal medium. Every five years an audit of the metering system would be required. If an audit indicates that the metering system is producing readings with errors greater than 5 percent, the purchaser would be required to initiate repair or replacement and retest the meter to demonstrate compliance with the 5 percent error limitation.
9. References
  IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
  https://www.ipcc.ch/report/2019-refinement-to-the-2006-ipcc-guidelines-for-national-greenhouse-gas-inventories/

  U.S. EPA (2021) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
  U.S. Environmental Protection Agency, Washington D.C. USEPA #430-R-21-005.
  https://www.epa.gov/sites/default/files/2021-04/documents/us-ghg-inventory-2021-main-text.pdf

  U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006.
  U.S. Environmental Protection Agency, Washington D.C. USEPA #430-R-08-005.
  https://www.epa.gov/sites/default/files/2015-12/documents/08_cr.pdf

  The EPA Center for Corporate Climate Leadership.
  https://www.epa.gov/climateleadership

  The EPA's Emissions & Generation Resource Integrated Database (eGRID).
  https://www.epa.gov/egrid

  The Climate Registry. https://www.theclimateregistry.org/

  The California Climate Action Registry.
  https://www.climateactionreserve.org/about-us/california-climate-action-registry/

  The California Air Resources Board (CARB) Mandatory Greenhouse Gas Reporting Regulation. https://ww2.arb.ca.gov/mrr-regulation

  The Oregon Greenhouse Gas Reporting Program.
  https://secure.sos.state.or.us/oard/displayDivisionRules.action?selectedDivision=1538

  The State of Washington Greenhouse Gas Reporting Program.
  https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases/Greenhouse-gas-reporting/Facility-greenhouse-gas-reports

  The United Kingdom's Carbon Reduction Commitment (CRC) program.
  https://www.gov.uk/government/collections/crc-energy-efficiency-scheme

  U.S. DOE Energy Information Administration (EIA) Annual Electric Power Industry Report, Form EIA-861. https://www.eia.gov/electricity/data/eia861/.

  EIA Voluntary Reporting of Greenhouse Gases Program.
  https://www.eia.gov/environment/pdfpages/0608s(2009)index.php

  EIA Manufacturing Energy Consumption Survey (MECS).
  https://www.eia.gov/consumption/manufacturing/data/2018/
  https://www.eia.gov/consumption/manufacturing/data/2018/xls/Table7_7.xlsx

  The Greenhouse Gas Protocol, Corporate Accounting and Reporting Standard, Revised Edition, World Resources Institute and World Business Council for Sustainable Development. https://ghgprotocol.org/corporate-standard

  EPA Climate Leaders Greenhouse Gas Inventory Protocol Core Module Guidance, Indirect Emissions from Purchases/Sales of Electricity and Steam.
  Climate_Leaders_GHG_Inventory_Protocol/Core_Module_Guidance/Indirect_Emissions_Purchases/Electricity_Steam

  U.S. DOE (2017) Combined Heat and Power Technology Fact Sheet Series
  https://www.energy.gov/eere/amo/combined-heat-and-power-basics 12/14/2021.

  U.S. Census Bureau, Business Dynamics Statistics (BDS) Survey (1978-2020).
  https://www.census.gov/programs-surveys/bds.html

  American National Standards Institute.
  ANSI C12.1-2022: Electric Meters - Code for Electricity Metering.
  https://webstore.ansi.org/standards/nema/ansic122022.


[Federal Register Volume 76, Number 189 (Thursday, September 29, 2011)]
[Notices]
[Page 60565]
[FR Doc No: 2011-25077]

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SECURITIES AND EXCHANGE COMMISSION

Proposed Collection; Comment Request

Upon Written Request, Copies Available From: Securities and Exchange
Commission, Office of Investor Education and Advocacy, Washington, DC
20549-0213.

Extension:
    Rule 15c2-1; SEC File No. 270-418; OMB Control No. 3235-0485.

    Notice is hereby given that pursuant to the Paperwork Reduction Act
of 1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange
Commission (``Commission'') is soliciting comments on the existing
collection of information provided for in Rule 15c2-1, (17 CFR
240.15c2-1), under the Securities Exchange Act of 1934 (15 U.S.C. 78a
et seq.). The Commission plans to submit this existing collection of
information to the Office of Management and Budget for extension and
approval.
    Rule 15c2-1 prohibits the commingling under the same lien of
securities of margin customers (a) with other customers without their
written consent and (b) with the broker or dealer. The rule also
prohibits the rehypothecation of customers' margin securities for a sum
in excess of the customer's aggregate indebtedness. Pursuant to Rule
15c2-1, respondents must collect information necessary to prevent the
rehypothecation of customer securities in contravention of the rule,
issue and retain copies of notices of hypothecation of customer
securities in accordance with the rule, and collect written consents
from customers in accordance with the rule. The information is
necessary to ensure compliance with the rule, and to advise customers
of the rule's protections.
    There are approximately 102 respondents (i.e., broker-dealers that
carry or clear customer accounts that also have bank loans) that
require an aggregate total of 2,295 hours to comply with the rule. Each
of these approximately 102 registered broker-dealers makes an estimated
45 annual responses. Each response takes approximately 0.5 hours to
complete. Thus, the total compliance burden per year is 2,295 burden
hours.
    Written comments are invited on: (a) Whether the proposed
collection of information is necessary for the proper performance of
the functions of the Commission, including whether the information
shall have practical utility; (b) the accuracy of the Commission's
estimates of the burden of the proposed collection of information; (c)
ways to enhance the quality, utility, and clarity of the information on
respondents; and (d) ways to minimize the burden of the collection of
information on respondents, including through the use of automated
collection techniques or other forms of information technology.
Consideration will be given to comments and suggestions submitted in
writing within 60 days of this publication.
    The Commission may not conduct or sponsor a collection of
information unless it displays a currently valid control number. No
person shall be subject to any penalty for failing to comply with a
collection of information subject to the PRA that does not display a
valid Office of Management and Budget (OMB) control number.
    Please direct your written comments to: Thomas Bayer, Director/
Chief Information Officer, Securities and Exchange Commission, c/o Remi
Pavlik-Simon, 6432 General Green Way, Alexandria, Virginia 22312 or
send an e-mail to<EMAIL_ADDRESS>
    Dated: September 23, 2011.
Elizabeth M. Murphy,
Secretary.
[FR Doc. 2011-25077 Filed 9-28-11; 8:45 am]
BILLING CODE 8011-01-P


[Federal Register Volume 76, Number 92 (Thursday, May 12, 2011)]
[Notices]
[Pages 27675-27677]
[FR Doc No: 2011-11611]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-64420; File No. SR-NYSE-2011-21]

Self-Regulatory Organizations; New York Stock Exchange LLC;
Notice of Filing of Proposed Rule Change Amending Rule 80C To Include
Additional Securities in the Pilot by Which Such Rule Operates and
Amending Rule 104 To Simplify Certain Aspects of the Text While Also
Conforming Certain of the Percentages Thereunder to the Proposed
Changes to Rule 80C

May 6, 2011.
    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
(``Act'') \1\ and Rule 19b-4 thereunder,\2\ notice is hereby given that
on May 4, 2011, New York Stock Exchange LLC (``NYSE'' or the
``Exchange'') filed with the Securities and Exchange Commission
(``SEC'' or ``Commission'') the proposed rule change as described in
Items I and II below, which Items have been prepared by NYSE. The
Commission is publishing this notice to solicit comments on the
proposed rule change, from interested persons.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
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I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    The Exchange proposes to amend Rule 80C to include additional
securities in the pilot by which such rule operates and amend Rule 104
to simplify certain aspects of the text while also conforming certain
of the percentages thereunder to the proposed changes to Rule 80C. The
text of the proposed rule change is available at the Exchange, the
Commission's Public Reference Room, and http://www.nyse.com.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, the self-regulatory organization
included statements concerning the purpose of, and basis for, the
proposed rule change and discussed any comments it received on the
proposed rule change. The text of those statements may be examined at
the places specified in Item IV below. The Exchange has prepared
summaries, set forth in sections A, B, and C below, of the most
significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
    The Exchange proposes to amend Rule 80C to include additional
securities in the pilot by which such rule operates and amend Rule 104
to simplify certain aspects of the text while also conforming certain
of the percentages thereunder to the proposed changes to Rule 80C.
    The Commission approved Rule 80C on a pilot basis on June 10, 2010
to provide for trading pauses in individual securities due to
extraordinary market volatility (``Trading Pause'') in all securities
included within the S&P 500[reg] Index (``S&P 500'') (``Trading Pause
Pilot'' or ``Pilot'').\3\ The Exchange noted in its filing to adopt
Rule 80C that during the Pilot period it would continue to assess
whether additional securities need to be added and whether the
parameters of Rule 80C would need to be modified to accommodate trading
characteristics of different securities. The Exchange subsequently
received approval to add to the Pilot the securities included in the
Russell 1000[supreg] Index (``Russell 1000'').\4\
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    \3\ The Commission approved the Trading Pause Pilot for all
equities exchanges and FINRA. See Securities Exchange Act Release
No. 62252 (June 10, 2010), 75 FR 34186 (June 16, 2010) (File Nos.
SR-BATS-2010-014; SR-EDGA-2010-01; SR-EDGX-2010-01; SR-BX-2010-037;
SR-ISE-2010-48; SR-NYSE-2010-39; SR-NYSEAmex-2010-46; SR-NYSEArca-
2010-41; SR-NASDAQ-2010-061; SR-CHX-2010-10; SR-NSX-2010-05; and SR-
CBOE-2010-047) and Securities Exchange Act Release No. 62251 (June
10, 2010), 75 FR 34183 (June 16, 2010) (SR-FINRA-2010-025). The
Exchange submitted a proposed rule change shortly after the initial
Commission approval order to clarify the procedures applicable to
reopening. See Securities Exchange Act Release No. 62284 (June 11,
2010), 75 FR 34498 (June 17, 2010) (SR-NYSE-2010-45).
    \4\ The Commission approved the addition to the Trading Pause
Pilot of the securities included in the Russell 1000 and a specified
list of Exchange Traded Products (``ETPs''), where applicable, for
all equities exchanges and FINRA. See Securities Exchange Act
Release No. 62884 (September 10, 2010), 75 FR 56618 (September 16,
2010) (File Nos. SR-BATS-2010-018; SR-BX-2010-044; SR-CBOE-2010-065;
SR-CHX-2010-14; SR-EDGA-2010-05; SR-EDGX-2010-05; SR-ISE-2010-66;
SR-NASDAQ-2010-079; SR-NYSE-2010-49; SR-NYSEAmex-2010-63; SR-
NYSEArca-2010-61; and SR-NSX-2010-08 and Securities Exchange Act
Release No. 62883 (September 10, 2010), 75 FR 56608 (September 16,
2010) (SR-FINRA-2010-033). The Exchange submitted a proposed rule
change shortly after the addition of the Russell 1000 securities to
extend the operation of the Pilot, which was set to expire on
December 10, 2010, until April 11, 2011. See Securities Exchange Act
Release No. 63500 (December 9, 2010), 75 FR 78309 (December 15,
2010) (SR-NYSE-2010-81). The Pilot is currently set to expire on the
earlier of August 11, 2011 or the date on which a limit up/limit
down mechanism to address extraordinary market volatility, if
adopted, applies. See Securities Exchange Act Release No. 64254
(April 7, 2011), 76 FR 20767 (April 13, 2011) (SR-NYSE-2011-16).

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    The Exchange has continued to assess whether additional securities
need to be added to the Pilot and whether the parameters of Rule 80C
need to be modified to accommodate trading characteristics of different
securities. In consultation with other markets and the staff of the
Commission, the Exchange proposes to include all NMS stocks within the
Pilot that are not already included therein, but to apply a wider
Threshold Move percentage to the newly added securities. Accordingly,
the Exchange proposes to delete Supplementary Material .10 to Rule 80C,
as the text therein would no longer be necessary.
    The Exchange proposes that the Threshold Move required to trigger a
Trading Pause for the proposed new securities be 30% or more for such
securities priced at $1 or higher and 50% or more for such securities
priced less than $1.\5\ The Exchange believes that these percentages
are commensurate with the characteristics shared by the proposed new
securities within these price ranges and would promote the objectives
of the Trading Pause Pilot to reduce the negative impacts of
unanticipated price movements in a security. In particular, the
proposed additional stocks are those not currently included in the S&P
500, Russell 1000, or specified ETPs, and therefore are more likely to
be less liquid securities or securities with lower trading volumes.
Accordingly, the Exchange believes that broader Threshold Move
percentages would be appropriate. Similarly, because leveraged ETPs
trade at a ratio against the associated index, a broader Threshold Move
percentage would also be appropriate for leveraged ETPs. In addition,
the Exchange believes that a 50% threshold move is appropriate for
securities trading under a dollar to reflect that price movements of
such lower-priced stocks equate to a higher percentage move than a
similar price change would be for a higher-priced stock.
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    \5\ Under the proposed rule change, the price of a security
would be based on the closing price on the previous trading day, or,
if no closing price exists, the last sale reported to the
Consolidated Tape on the previous trading day.
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    The Exchange proposes to include new subsections 80C(a)(i), (ii)
and (iii) to reflect the distinction between the applicable Threshold
Move percentages for current Pilot securities and the proposed new
securities to be included within the Pilot.\6\ The Exchange is not
proposing any other changes to the text of Rule 80C or the operation of
the Pilot, and will continue to assess whether the parameters for
invoking a Trading Pause continue to be appropriate and whether the
parameters should be modified.
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    \6\ The Exchange is not proposing a change to the Threshold Move
percentage applicable to securities currently included within the
current Pilot. However, the changes proposed herein would require
that certain rule text pertaining to the Threshold Move for the
existing Pilot securities be reorganized within Rule 80C.
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    The proposed changes to the Pilot, if approved, would require that
the text of Rule 104(a)(1)(B)(iii) and (iv), which pertains to the
pricing obligations that Designated Market Makers (``DMMs'') are
required to adhere to, be amended to correct the cross-references
therein to Rule 80C and the Threshold Move thereunder. Specifically,
the Exchange proposes to remove any text from Rule 104(a)(1)(B)(iii)
and (iv) addressing NMS stocks that are not subject to the Pilot
because no such securities would exist and such text would therefore be
unnecessary. The Exchange also proposes to simplify Rule
104(a)(1)(B)(iii) and (iv) by explicitly stating the percentages that
are applicable thereunder and the times during the trading day when
Rule 80C is not in effect. The Exchange notes that part of this
proposed change would be substantive, in that the percentages under
Rule 104(a)(1)(B)(iii) and (iv) would decrease slightly for the
proposed new securities priced at $1 or greater. The Exchange believes
that this proposed substantive change would not have a significant
impact on DMM pricing obligations and is reasonable because it would
ensure that the designated quoting percentages in Rule 104(a)(1)(B) are
within a narrower range than the percentages necessary to trigger a
Trading Pause.
2. Statutory Basis
    The proposed rule change is consistent with Section 6(b) of the
Securities Exchange Act of 1934 (the ``Act''),\7\ in general, and
furthers the objectives of Section 6(b)(5),\8\ in particular, in that
it is designed to prevent fraudulent and manipulative acts and
practices, to promote just and equitable principles of trade, to foster
cooperation and coordination with persons engaged in facilitating
transactions in securities, and to remove impediments to and perfect
the mechanism of a free and open market and a national market system.
The proposed rule change also is designed to support the principles of
Section 11A(a)(1) \9\ of the Act in that it seeks to ensure fair
competition among brokers and dealers and among exchange markets. The
Exchange believes that the proposed rule meets these requirements
because it expands the scope of the Pilot to cover all NMS stocks while
adjusting the parameters of the rule for different securities in a
manner that will promote uniformity across markets concerning decisions
to pause trading in a security when there are significant price
movements. Additionally, the proposed changes would ensure that the
designated quoting percentages in Rule 104(a)(1)(B) are within a
narrower range than the percentages necessary to trigger a Trading
Pause.
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    \7\ 15 U.S.C. 78f(b).
    \8\ 15 U.S.C. 78f(b)(5).
    \9\ 15 U.S.C. 78k-1(a)(1).
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B. Self-Regulatory Organization's Statement on Burden on Competition

    The Exchange does not believe that the proposed rule change will
impose any burden on competition that is not necessary or appropriate
in furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants, or Others

    No written comments were solicited or received with respect to the
proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    Within 45 days of the date of publication of this notice in the
Federal Register or within such longer period (i) as the Commission may
designate up to 90 days of such date if it finds such longer period to
be appropriate and publishes its reasons for so finding or (ii) as to
which the self-regulatory organization consents, the Commission will:
    (A) By order approve or disapprove such proposed rule change, or
    (B) Institute proceedings to determine whether the proposed rule
change should be disapproved.

IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or

     Send an e-mail to<EMAIL_ADDRESS>Please include
File Number SR-NYSE-2011-21 on the subject line.

Paper Comments

     Send paper comments in triplicate to Elizabeth M. Murphy,
Secretary, Securities and Exchange Commission, 100 F Street, NE.,
Washington, DC 20549-1090.

All submissions should refer to File Number SR-NYSE-2011-21. This file
number should be included on the subject line if e-mail is used. To
help the Commission process and review your comments more efficiently,
please use only one method. The Commission will post all comments on
the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all
written statements with respect to the proposed rule change that are
filed with the Commission, and all written communications relating to
the proposed rule change between the Commission and any person, other
than those that may be withheld from the public in accordance with the
provisions of 5 U.S.C. 552, will be available for Web site viewing and
printing in the Commission's Public Reference Room, 100 F Street, NE.,
Washington, DC 20549, on official business days between the hours of 10
a.m. and 3 p.m. Copies of such filing also will be available for
inspection and copying at the principal office of NYSE. All comments
received will be posted without change; the Commission does not edit
personal identifying information from submissions. You should submit
only information that you wish to make publicly available. All
submissions should refer to File Number SR-NYSE-2011-21 and should be
submitted on or before June 2, 2011.
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    \10\ 17 CFR 200.30-3(a)(12).

    For the Commission, by the Division of Trading and Markets,
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pursuant to delegated authority.\10\

Elizabeth M. Murphy,
Secretary.
[FR Doc. 2011-11611 Filed 5-11-11; 8:45 am]
BILLING CODE 8011-01-P