MEMORANDUM

To: Docket # EPA-HQ-OAR-2011-0512

From: Mark de Figueiredo, EPA/CCD

Date: November 10, 2014

Subject: Review for Potential Disclosure Concerns for New and Revised Inputs to 

Emission Equations in the “Greenhouse Gas Reporting Rule: 2014 Revisions 

and Confidentiality Determinations for Petroleum and Natural Gas Systems; Final 

Rule”

In the rulemaking titled “Greenhouse Gas Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems; Final Rule” (hereinafter 

referred to as the Subpart W 2014 Amendments), the EPA is revising several of the subpart W 

reporting data elements and adding several new reporting data elements. These new and revised 

data elements include data elements that are the actual values used to calculate GHG emissions. 

As explained in the preambles to the proposed and final rules1, we assigned these new and 

revised inputs to the “Inputs to Emission Equations” data category and evaluated potential 

disclosure concerns for these data elements. We followed the same steps set forth in a supporting 

memorandum2 accompanying the proposed rule addressing inputs to emission equations that 

were deferred until 2015. 3 These steps are the following:

• Step 1: Determine whether each input is already publicly available. 

• Step 2: For inputs that are not publicly available, evaluate whether release of the 

information is likely to result in substantial competitive harm. 

• Step 3: For inputs that are likely to cause substantial competitive harm if disclosed, 

evaluate potential alternative calculation methods. 

• Step 4: For inputs that are likely to cause substantial competitive harm if disclosed, 

evaluate potential alternative verification methods. 

The purpose of this memorandum is to document this evaluation for the final list of new 

and revised inputs to emissions equations and to explain the reasons for changes in the list since 

proposal. The list of the final new and revised inputs to emissions equations is provided in 

Appendix A.

1 See 79 FR 13394, March 10, 2014 for the proposed rule, and see Docket Id. No. EPA-HQ-OAR-2011-0512 for the 

final rule.

2 See memorandum titled “Process for Evaluating and Potentially Amending Part 98 Inputs to Emission Equations,”

Docket ID No. EPA-HQ-OAR-2010-0929-0037. 3 See 78 FR 55994, September 11, 2013 for the proposed rule, and see 79 FR 63750, October 24, 2014 for the final 

rule.

1

 
1. Changes to the List of Inputs Since Proposal

The list in Appendix A includes 17 new and revised inputs that were not on the list in the 

proposed memorandum evaluating the inputs to equations for this action, and one input on the 

proposed list has been removed from the final list.

Seven of the inputs added to the final list in Appendix A were added because we 

determined while preparing the final amendments package that they are inputs to an emissions 

equation under certain conditions. Five of the seven data elements are inputs when the data used 

in the emission calculation are from only one well. The inputs that meet this condition are the 

cumulative gas flowback time used in Equation W-10A (§98.236(g)(5)(i)), the average daily gas 

production rate for completions without hydraulic fracturing used in Equation W-13B with and 

without flaring (§98.236(h)(1)(iv) and (h)(2)(iv), respectively), the volume of oil produced 

during periods in which associated gas was vented or flared as used in Equation W-18 

(§98.236(m)(5)), and the total volume of associated gas sent to sales during time periods in 

which associated gas was vented or flared as used in Equation W-18 (§98.236(m)(6)). 

Additionally, the total number of blowdowns is an input to Equation 14A or 14B when 

blowdowns occurred for only one unique physical volume for a particular equipment type 

(§98.236(i)(1)(i)), and the time gas-liquid separator dump valves did not close properly is an 

input to Equation W-16 when only one separator had a dump valve that did not close properly 

(§98.236(j)(3)(ii)). In situations where data are not inputs to emission equations, these data 

elements are assigned to the “Unit/Process Operating Characteristics that are Not Inputs to 

Emission Equations” data category. Thus, confidentiality determinations were developed for 

these data elements as discussed in the memorandum titled “Final Data Category Assignments 

and Confidentiality Determinations for Data Elements (excluding inputs to emission equations) 

in the “Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; Final Rule” (see Docket Id. No. EPA-HQ-OAR-2011-

0512).

Four of the inputs added to the final list in Appendix A were improperly assigned to the 

“Unit/Process Operating Characteristics that are Not Inputs to Emission Equations” data 

category for the proposed rule. These data elements are the average flow rate from tested oil 

wells in barrels of oil per day for the well(s) tested where emissions are not vented to a flare 

(§98.236(l)(1)(iv)) and where emissions are vented to a flare (§98.236(l)(2)(iv)). These data 

elements are direct inputs to Equation W-17A when all of the emissions from tested wells are 

either vented to atmosphere or vented to a flare. However, in situations where emissions from 

some tested wells are vented to atmosphere and others are vented to flares, the two average 

values can be combined with the reported number of tested wells vented to atmosphere and the 

reported number of tested wells vented to flare to calculate the average oil flow rate that is used 

in Equation W-17A. As a result, the two separately reported oil volumes are effectively inputs. A 

similar situation applies for the average annual gas production rates when emissions from tested 

gas wells are either vented to atmosphere or vented to flare (§98.236(l)(3)(iii) and (l)(4)(iii), 

respectively); these values are effectively inputs to Equation W-17B.

Three of the inputs added to the final list in Appendix A were included in the reporting 

requirements in the proposed rule, but they were inadvertently not assigned to a data category in 

the analysis at proposal. For the final rule, the three data elements have been assigned to the 

inputs to emission equations data category because they are used directly in equations. These 

inputs are the measured flow rate for as found measurements of reciprocating compressors, 

2
which is an input in Equation W-28 (§98.236(p)(3)(i)(D)); the total number of meter/regulator 

runs at above grade transmission-distribution transfer stations, which is an input in Equation W32B (§98.236(r)(2)(iii)); and the average estimated time that each meter/regulator run at above 

grade metering-regulating stations that are not above grade transmission-distribution transfer 

stations was operational, which is an input in Equation W-32B (§98.236(r)(2)(iv)). One 

additional element that was inadvertently omitted from the reporting requirements in the 

proposed rule has also been assigned to the Inputs to Emissions Equations data category for the 

final rule. This input is the measured vented or flared flowback rate at the beginning of the 

period of time when sufficient quantities of gas are present to enable separation that is used in 

Equation W-10B (§98.236(g)(6)(ii)).

In consideration of comments, the EPA has revised the method in the final rule for 

calculating equipment leak emissions from meter/regulator runs at above grade transmissiondistribution transfer stations. The revised method requires annual estimation of emissions from 

all meter/regulator runs at the facility, not just the meter/regulator runs that were surveyed in the 

calendar year. Thus, we also added requirements in the final rule to report the total number of 

meter/regulator runs at the facility and the estimated time that each meter/regulator run was 

operational in the calendar year (§98.236(q)(3)(ix)(A) and (q)(3)(ix)(B)). These data elements 

are inputs to Equation W-32B.

The number of atmospheric tanks in the sub-basin for which emissions were calculated 

using Calculation Method 3 and that did not control emissions with flares is not an input; thus, 

this data element was removed from the final list in Appendix A (§98.236(j)(2)(ii)(B)).

2. Evaluation of the Proposed Subpart W Inputs

2.1 Step 1: Public Availability

In the first step, we conducted a literature search to identify publicly available data that 

are identical to the new and revised inputs. Data sources reviewed included the following:

• Department of Energy, Energy Information Administration - www.eia.gov

• Department of Energy, Federal Energy Regulatory Commission – www.ferc.gov

• Department of Transportation, Pipeline and Hazardous Materials Safety Administration: 

Data and Statistics - www.phmsa.dot.gov

• American Petroleum Institute: Industry Statistics - www.api.org/statistics

• American Gas Association - www.aga.org

• Railroad Commission of Texas - www.rrc.state.tx.us/data/index.php

Public data identified during our literature search were evaluated on whether they were 

the same as the new and revised inputs by considering the number of reporters represented by the 

data, the age of the data, and frequency of availability. Although we were able to locate some 

data that were similar to some of the new and revised inputs, we were unable to locate any public 

sources of data that are exactly the same as the new and revised inputs, reported by the same 

reporters, and available on a recurring basis. As a result, the EPA proceeded to Step 2 of the 

evaluation.

3
2.2 Step 2: Review for Potential Disclosure Concerns

In Step 2, we examined both the market structure for each industry segment affected by 

the final subpart W 2014 amendments4 and the new and revised inputs to determine whether 

disclosure concerns existed. We focused on the market structure of each industry segment

because the structure of the market in which a reporter does business has a significant impact on 

the ability of a competitor to use the reported information to gain competitive advantage. 

Typically, economists use market concentration to assess market conditions and use tools such as 

the Herfindahl-Hirshchman Index to assess market concentration. However, HerfindahlHirshman Index values are not available for the petroleum and natural gas industry segments. As 

a result, the EPA conducted a qualitative analysis of the market structure for each of the affected 

industry segments and assessed potential concerns for each industry segment. The results of our 

analysis for each segment are summarized below.

Onshore Petroleum and Natural Gas Production Segment. The onshore petroleum and 

natural gas production segment covers emissions related to onshore production wellheads. The 

market structures for petroleum and natural gas were considered separately for this segment.

Onshore petroleum production is a regionally concentrated market, with wells located in 

fixed geological formations. Decisions on where to drill wells may be based on proprietary 

information during the early development of a formation when lease prices have not stabilized 

and operators are taking risks by drilling exploratory wells in formations that do not have proven 

production records. After several wells have been drilled in an area, information about 

production becomes publicly available and the advantage incurred by the operator drilling 

exploration wells is lost. However, once a well has been drilled, decisions to produce are based 

on market prices and the ability to control flow from the well. Although this could pose a 

potential data sensitivity with respect to exploration wells, for most exploratory wells this issue 

is addressed by the fact that onshore production data is reported at a sub-basin level, as defined 

by county boundaries, and which is a large enough scale that disclosure of the data collected 

under subpart W would not reveal any proprietary information about the facility or cost to do 

business. However, for two specific types of exploratory wells, delineation wells and wildcat 

wells, in specific cases discussed below, early public disclosure of four “inputs to emission 

equations” data elements could reveal the productivity of the oil wells and therefore result in loss 

of investment value. The four “inputs to emission equations” data elements are:

• For oil well testing, if oil well testing is performed where emissions are not vented to a 

flare, the average flow rate in barrels of oil per day for well(s) tested (§98.236(l)(1)(iv)); 

• For oil well testing, if oil well testing is performed where emissions are vented to a flare, 

the average flow rate in barrels of oil per day for well(s) tested (§98.236(l)(2)(iv));

• For associated gas venting and flaring, volume of oil produced, in barrels, in the calendar 

year during the time periods in which associated gas was vented or flared 

(§98.236(m)(5)); and 

4 The offshore petroleum and natural gas production industry segment was not examined in this analysis because 

none of the data elements for this industry segment are assigned to the “Inputs to Emission Equations” data 

category.

4

 
• For associated gas venting and flaring, total volume of associated gas sent to sales, in 

standard cubic feet, in the calendar year during time periods in which associated gas was 

vented or flared (§98.236(m)(6)).

The specific cases for which early public disclosure of these four “inputs to emission 

equations” data elements could reveal the productivity of the oil wells and result in loss of 

investment value are as follows:

• For oil well testing, where wildcat wells and/or delineation wells are the only wells in a 

sub-basin that are tested. If wildcat and/or delineation wells are the only wells that are

tested, then the inputs could reveal information on the productivity of the well. 

• For associated gas venting and flaring, where wildcat wells and/or delineation wells are 

the only wells in a sub-basin. If wildcat wells and/or delineation wells are the only wells 

in a sub-basin, then the volumes of oil produced and associated gas sent to sales would 

represent volumes of wildcat wells and/or exploratory wells exclusively, which could 

reveal information on the productivity of the well.

Delaying reporting of these data for two reporting years would be sufficient time for 

reporters to thoroughly conduct an assessment of the well, after which the data could be reported 

and made publicly available. Besides the need for a two-year delay for the four data elements 

associated with exploratory wells in the specific cases described above, the likelihood of harm 

can be characterized for all information collected for this segment and would not be likely to 

reveal any proprietary information or information about the cost to do business. Thus, the EPA 

did not proceed to evaluate each “input to emission equations” data element in this segment.

The onshore natural gas production market overlaps many of the geological formations of 

petroleum production. Furthermore, the market itself is structured the same, with a large number 

of operators within each formation. Like onshore oil production, disclosure of data for onshore 

natural gas production at the sub-basin level would not reveal any proprietary information about 

the facility or cost to do business, except for two specific types of exploratory wells, delineation 

wells and wildcat wells, in the specific cases discussed below. In these specific cases, early 

public disclosure of six “inputs to emission equations” data elements could reveal the 

productivity of the gas wells and therefore result in loss of investment value. The six “inputs to 

emission equations” data elements are:

• For gas well completions or workovers with hydraulic fracturing in a sub-basin and well 

type combination category, the cumulative gas flowback time, in hours, from when gas is 

first detected until sufficient quantities are present to enable separation, and the 

cumulative flowback time, in hours, after sufficient quantities are present to enable 

separation (sum of “Tp,i” and sum of “Tp,s” values used in Equation W-10A)

(§98.236(g)(5)(i)); 

• For gas well completions or workovers with hydraulic fracturing in a sub-basin and well 

type combination category, the flowback rate for the measured well, in standard cubic 

feet per hour (§98.236(g)(5)(ii));

• For each sub-basin with gas well completions without hydraulic fracturing and without

flaring, the average daily gas production rate for all completions without hydraulic 

5
fracturing in the sub-basin without flaring, in standard cubic feet per hour 

(§98.236(h)(1)(iv));

• For each sub-basin with gas well completions without hydraulic fracturing and with 

flaring, the average daily gas production rate for all completions without hydraulic 

fracturing in the sub-basin with flaring, in standard cubic feet per hour 

(§98.236(h)(2)(iv)); 

• For gas well testing, if gas well testing is performed where emissions are not vented to a 

flare, the average annual production rate in actual cubic feet per day for well(s) tested 

(§98.236(l)(3)(iii)); and 

• For gas well testing, if gas well testing is performed where emissions are vented to a 

flare, the average annual production rate in actual cubic feet per day for well(s) tested 

(§98.236(l)(4)(iii)).

The specific cases for which early public disclosure of these six “inputs to emission 

equations” data elements could reveal the productivity of the gas wells and result in loss of 

investment value are as follows:

• For gas well completions or workovers with hydraulic fracturing, where wildcat wells 

and/or delineation wells are the only wells in a sub-basin and well type combination 

category that can be used for the measurement. These measurements require the use of 

“representative” wells. If wildcat and/or delineation wells are the only wells that can be 

used for measurement of these data, then the inputs could reveal information on the 

productivity of the well.

• For gas well completions without hydraulic fracturing, where wildcat wells and/or 

delineation wells are the only wells in a sub-basin that can be used the measurement. If 

wildcat and/or delineation wells are the only wells that can be used for measurement of 

these data, then the inputs could reveal information on the productivity of the well.

• For gas well testing, where wildcat wells and/or delineation wells are the only wells in a 

sub-basin that are tested. If wildcat and/or delineation wells are the only wells that are 

tested, then the inputs could reveal information on the productivity of the well.

As for oil wells, delaying reporting of these data for two reporting years would be 

sufficient time for reporters to thoroughly conduct an assessment of the well, after which the data 

could be reported and made publicly available. Besides the need for a two-year delay for the six 

data elements associated with exploratory wells in the specific cases described above, the 

likelihood of harm can be characterized for all information collected for this segment and would 

not be likely to reveal any proprietary information or information about the cost to do business. 

Thus, the EPA did not proceed to evaluate each “input to emission equations” data element in 

this segment.

Onshore Natural Gas Processing Segment. Natural gas processors are regionally located 

close to production wellheads. The segment itself is large, with roughly 500 plants and almost 

250 owner companies. These plants are located in close proximity to given natural gas plays, 

generally accepting input gas via pipeline, and competing in regional markets. There is market 

concentration, even at the national level: the top 10% of owner companies control 64% of the 

processing capacity, according to EIA’s 2012 processing capacity database. Thus, firms are 

6
aware of their competitors and release of data revealing production costs, operating efficiency, or 

market share could cause competitive harm. Data elements of potential concern include the 

quantity of natural gas received, the quantity of residue gas leaving the plant, and the quantities 

of individual NGLs produced. These data elements are not inputs to equations. Thus, we believe 

that the regional concentration of firms in this segment would not pose data sensitivity concerns, 

because the “inputs to equations” data elements in this segment listed in Appendix would not be 

likely to reveal any proprietary information about the facility, cost of natural gas, or cost to do 

business. 

Natural Gas Transmission Compression Segment. Natural gas transmission 

compression operators transport natural gas from processors to end users. Firms are regionally 

concentrated, having control over particular segments of the pipeline infrastructure. The limited

number of firms and the regional concentration could pose data sensitivity issues.

Firms in the natural gas pipeline transmission segment compete with others in their 

region for shipments of natural gas. Even though there may be only one pipeline transmitting

natural gas from one location to another, competition exists between firms that wish to accept 

shipments of natural gas within a given region for transmission to potentially different endpoints. 

Such firms could make use of information about their competitors’ throughput quantity and/or 

cost structure to strategically set their prices or other contract terms. Even though the market is 

regulated by FERC, actual contract prices may be set at levels below the FERC-mandated 

maximum tariff. As a result, throughput or other data elements that can be used to estimate 

throughput should be evaluated to determine if they are available elsewhere, and if not, whether 

they would reveal information about a firm’s throughput or costs that could be used by 

competing firms to gain a competitive advantage. Such data elements are not “inputs to 

equations”. Thus, the data elements listed in Appendix A would not be likely to reveal any 

proprietary information or information about the cost to do business for facilities in this industry 

segment.

Natural Gas Distribution Segment. Natural gas distributers own and operate the 

distribution mains and services and function as the middle man between transmission lines and 

end-users. This market is regionally located with distributers having exclusive access to specific 

cities and other localities. Both publicly- and privately-owned companies are highly regulated, 

unable to charge market based rates for service. The regulation by government and the monopoly 

rights distributors hold over given regions prevents competitors’ use of the data for strategic 

purposes. As a result, the “inputs to equations” data elements in this segment would not be likely 

to reveal any proprietary information about the facility or cost to do business. 

Underground Natural Gas Storage Segment. Underground natural gas storage is used to 

smooth out volatility in consumption and use of natural gas. The market is regional; facilities are 

located either near major distribution centers or near oil and gas fields. Even with the regional 

market structure, competitors are not known to engage in strategic competition in building 

storage facilities. First, facilities are built in response to other upstream factors, such as increased 

gas supply coming to distributors, not to undermine other competitors. Second, storage firms are 

constrained by the geographical and geological requirements needed for underground storage, 

preventing firms from moving in and increasing their market share. Finally, storage technology 

is widely known and not used to garner a competitive advantage. As a result, the “inputs to 

equations” data elements in this segment would not be likely to reveal any proprietary 

information about the facility or cost to do business. 

7
Liquefied Natural Gas Storage Segment. Liquefied natural gas (LNG) storage operates 

much the same as underground natural gas storage, with storage used to smooth volatility related 

to consumption. The small size of the LNG storage market could create the possibilities for 

disruptive competitive undercutting; however, in this case, we believe that this is unlikely for the 

following two reasons: First, LNG storage is primarily owned by highly regulated distributors, 

preventing competitive firms from undercutting the market. Second, LNG storage occurs in 

response to increase supply upstream or decreased demand downstream and is not responsive to 

cost advantages. As a result, the “inputs to equations” data elements in this segment would not be 

likely to reveal any proprietary information about the facility or cost to do business. 

Liquefied Natural Gas Import/Export Segment. Currently the U.S. has only 12 LNG 

import terminals and one LNG export terminal. There are nine onshore import terminals and 

three offshore import terminals. LNG technology is not proprietary. The technology is relatively 

simple and has been available for many years. The market is regional and small with import 

terminals located along the Gulf and East coasts. Although there are a small number of facilities 

that import and/or export LNG, they may be viewed as a part of the larger natural gas supply 

sector that is a much larger market. The product delivered or consumed by LNG Import/Export is 

identical to the product generated in onshore and offshore natural gas production. Functionally, 

Import and Export terminals may be considered as a large producer or consumer of natural gas. 

Import and Export terminals are generally located in regions of supply restrictions or excess to 

maximize price margins. However, the trading prices of natural gas are publicly available and the 

building of new import and export terminals is limited by capital and permitting, not by market 

structure. Release of information about import/export terminals would not be likely to change the 

operations of other firms in the market. As a result, the “inputs to equations” data elements in 

this segment would not be likely to reveal any proprietary information about the facility or cost 

to do business. 

2.3 Step 3 and Step 4

As noted above, disclosure of some of the inputs listed in Appendix A were determined 

to have early disclosure concerns in situations where the inputs are specific to exploratory wells. 

The EPA addressed this concern by providing an option in the final rule that allows reporters to 

delay reporting of these inputs for up to two years. In light of this option and the above analysis 

for Steps 1 and 2, the EPA did not proceed to further evaluate the “inputs to equations” data 

elements in subpart W under Steps 3 and 4.

8
Appendix A

List of New and Revised Inputs to Emission Equations 

Affected by the Subpart W 2014 Amendments
Table A-1. List of New and Revised Inputs to Emission Equations

Affected by the Subpart W 2014 Amendments

Rule Citation Final Data Element

Natural Gas Pneumatic Device Venting

§98.236(b)(2) For each type of pneumatic device, the estimated average number of hours in the 

calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of 

this section were operating in the calendar year (“Tt” in Equation W-1 of this subpart).

Natural Gas Pneumatic Pump Venting

§98.236(c)(2) Average estimated number of hours in the calendar year the pumps were operational

(“T” in Equation W-2 of this subpart). 

Acid Gas Removal

§98.236(d)(1)(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate 

based on process knowledge or best available data, in million cubic feet per year.

§98.236(d)(2)(i)(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.

§98.236(d)(2)(iii)(B) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the natural 

gas feed temperature, in degrees Fahrenheit.

§98.236(d)(2)(iii)(C) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the natural 

gas feed pressure, in pounds per square inch.

§98.236(d)(2)(iii)(D) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the natural

gas flow rate, in standard cubic feet per minute.

§98.236(d)(2)(iii)(E) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the acid gas 

content of the feed natural gas, in mole percent.

§98.236(d)(2)(iii)(F) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the acid gas 

content of the outlet natural gas, in mole percent.

§98.236(d)(2)(iii)(G) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the unit 

operating hours, excluding downtime for maintenance or standby, in hours per year.

§98.236(d)(2)(iii)(H) For each unit for which Calculation Methodology 4 in §98.233(d) is used, the exit 

temperature of the natural gas, in degrees Fahrenheit.

§98.236(d)(2)(iii)(I) For each unit for which Calculation Methodology 4 in §98.233(d) is used, solvent 

pressure, in pounds per square inch.

§98.236(d)(2)(iii)(J) For each unit for which Calculation Methodology 4 in §98.233(d) is used, solvent 

temperature, in degrees Fahrenheit.

§98.236(d)(2)(iii)(K) For each unit for which Calculation Methodology 4 in §98.233(d) is used, solvent 

circulation rate, in gallons per minute.

§98.236(d)(2)(iii)(L) For each unit for which Calculation Methodology 4 in §98.233(d) is used, solvent 

weight, in pounds per gallon.

Dehydrators

§98.236(e)(1)(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.

§98.236(e)(1)(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.

§98.236(e)(1)(vi) Dehydrator absorbent circulation rate, in gallons per minute.

Liquids Unloading

§98.236(f)(1)(vi) Cumulative amount of time wells were vented (sum of “Tp” from Equation W-7A or 

W-7B of this subpart), in hours.

A-2
Table A-1. List of New and Revised Inputs to Emission Equations

Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element

Gas Well Completions and Workovers with Hydraulic Fracturing

§98.236(g)(5)(i)5 If you used Equation W-10A to calculate annual volumetric total gas emissions, the 

cumulative gas flowback time, in hours, from when gas is first detected until sufficient 

quantities are present to enable separation, and the cumulative flowback time, in hours, 

after sufficient quantities of gas are present to enable separation (sum of “Tp,i” and sum 

of “Tp,s” values used in Equation W-10A).

§98.236(g)(6)(i) If you used Equation W-10B to calculate annual volumetric total gas emissions, the 

vented natural gas volume, in standard cubic feet, for each well in the sub-basin

(“FVs,p” in Equation W-10B).

§98.236(g)(6)(ii) If you used Equation W-10B to calculate annual volumetric total gas emissions for 

completions or workovers that vent gas to the atmosphere or flare, the flow rate at the 

beginning of the period of time when sufficient quantities of gas are present to enable 

separation, in standard cubic feet per hour, for each well in the sub-basin (“FRp,i” in 

Equation W-10B).

Gas Well Completions and Workovers without Hydraulic Fracturing

§98.236(h)(1)(iv)6 The average daily gas production rate for all completions without hydraulic fracturing 

in the sub-basin without flaring, in standard cubic feet per hour (average of all “Vp” 

used in Equation W-13B).

§98.236(h)(2)(iv)7 The average daily gas production rate for all completions without hydraulic fracturing 

in the sub-basin with flaring, in standard cubic feet per hour (the average of all “Vp” 

from Equation W-13B).

Blowdown Vent Stacks

§98.236(i)(1)(i)8 Total number of blowdowns in the calendar year for the equipment or event type (sum 

of equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for 

all unique physical volumes for the equipment or event type).

Onshore Production Storage Tanks

§98.236(j)(3)(ii)9 If any of the gas-liquid separator dump valves did not close properly during the 

reporting year, the total time, in hours, the dump valves did not close properly (sum of 

the “Tn” values used in Equation W-16).

Transmission Storage Tanks

§98.236(k)(2)(ii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and 

the vent stack vented directly to the atmosphere during the calendar year, the measured 

leak rate (average leak rate from a continuous flow measurement device), in standard 

cubic feet per hour.

5 These data elements are inputs only when reported information is based on data for a single well. 6 This data element is an input only when reported information is based on data for a single well.

7 This data element is an input only when reported information is based on data for a single well.

8 This data element is an input only when reported information is based on data for a single unique physical volume 

for a particular equipment type.

9 This data element is an input only when reported information is based on data for a single gas-liquid separator with 

a dump valve that did not close properly.

A-3

 
Table A-1. List of New and Revised Inputs to Emission Equations

Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element

§98.236(k)(2)(iii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and 

the vent stack vented directly to the atmosphere during the calendar year, the duration 

of time that the leak is counted as having occurred, in hours, as determined in 

§98.233(k)(3) (may use best available data if a continuous flow measurement device 

was used).

§98.236(k)(3)(ii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and 

the vent stack vented to a flare during the calendar year, the measured leakage rate 

(average leak rate from a continuous flow measurement device), in standard cubic feet 

per hour.

§98.236(k)(3)(iii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and 

the vent stack vented to a flare during the calendar year, the duration of time that 

flaring occurred in hours as defined in §98.233(k)(3) (may use best available data if a 

continuous flow measurement device was used).

Well Testing 

§98.236(l)(1)(iv) If oil well testing is performed where emissions are not vented to a flare, the average 

flow rate for well(s) tested, in barrels of oil per day.

§98.236(l)(2)(iv) If oil well testing is performed where emissions are vented to a flare, the average flow 

rate for well(s) tested, in barrels of oil per day.

§98.236(l)(3)(iii) If gas well testing is performed where emissions are not vented to a flare, the average 

annual production rate for well(s) tested, in actual cubic feet per day.

§98.236(l)(4)(iii) If gas well testing is performed where emissions are vented to a flare, the average 

annual production rate for well(s) tested, in actual cubic feet per day.

Associated Natural Gas

§98.236(m)(5)10 Volume of oil produced, in barrels, in the calendar year during time periods in which 

associated gas was vented or flared (the sum of “Vp,q” used in Equation W-18 of this 

subpart).

§98.236(m)(6)11 Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year 

during time periods in which associated gas was vented or flared (the sum of “SG” 

values used in Equation W-18 of §98.233(m)).

Flare Stacks

§98.236(n)(7) Mole fraction of CH4 in the feed gas to the flare (“XCH4” in Equation W-19 of this 

subpart).

§98.236(n)(8) Mole fraction of CO2 in the feed gas to the flare (“XCO2” in Equation W-20 of this 

subpart).

Centrifugal Compressors

§98.236(o)(3)(i)(D) If the measurement methods specified in paragraphs §98.233(o)(2) or (o)(4) are 

conducted, then for each as found measurement performed on a leak or vent, the 

measured flow rate, in standard cubic feet per hour.

§98.236(o)(3)(ii)(B) For each compressor mode-source combination where a reporter emission factor as 

calculated in Equation W-23 was used to calculate emissions in Equation W-21, the 

compressor mode-source combination reporter emission factor, in standard cubic feet 

per hour (“EFs,m” in Equation W-23).

10 This data element is an input only when reported information is based on data for a single well. 11 This data element is an input only when reported information is based on data for a single well.

A-4

 
Table A-1. List of New and Revised Inputs to Emission Equations

Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element

§98.236(o)(3)(ii)(C) For each compressor mode-source combination where a reporter emission factor as 

calculated in Equation W-23 was used to calculate emissions in Equation W-21, the 

total number of compressors measured in the compressor mode-source combination in 

the current reporting year and the preceding two reporting years (“Countm” in Equation 

W-23).

§98.236(o)(4)(ii) If the measurement methods specified in paragraphs §98.233(o)(3) or (o)(5) are 

conducted, report the measured volume of flow during the reporting year, in million 

standard cubic feet.

§98.236(o)(5)(i) For centrifugal compressors with wet seal degassing vents in onshore petroleum and 

natural gas production, the number of centrifugal compressors that have wet seal oil 

degassing vents. 

Reciprocating Compressors

§98.236(p)(3)(i)(D) If the measurement methods specified in paragraphs §98.233(p)(2) or (p)(4) are 

conducted, then for each as found measurement performed on a leak or vent, the 

measured flow rate, in standard cubic feet per hour.

§98.236(p)(3)(ii)(B) For each compressor mode-source combination where a reporter emission factor as 

calculated in Equation W-28 was used to calculate emissions in Equation W-27, the 

compressor mode-source combination reporter emission factor, in standard cubic feet 

per hour (“EFs,m” in Equation W-28).

§98.236(p)(3)(ii)(C) For each compressor mode-source combination where a reporter emission factor as 

calculated in Equation W-28 was used to calculate emissions in Equation W-27, the 

total number of compressors measured in the compressor mode-source combination in 

the current reporting year and the preceding two reporting years (“Countm” in Equation 

W-28).

§98.236(p)(4)(ii) If the measurement methods specified in paragraphs §98.233(p)(3) or (p)(5) are 

conducted, the measured volume of flow during the reporting year, in million standard 

cubic feet.

Equipment Leak Surveys

§98.236(q)(3)(ix)(A) The total number of meter/regulator runs at above grade transmission-distribution 

transfer stations at your facility (“CountMR” in Equation W-32B of this subpart).

§98.236(q)(3)(ix)(B) Average estimated time that each meter/regulator run at above grade transmissiondistribution transfer stations was operational in the calendar year, in hours per 

meter/regulator run (“Tw,avg” in Equation W-32B of this subpart).

Equipment Leaks by Population Counts

§98.236(r)(1)(iii) Average estimated time that the emission source type was in operation in the calendar 

year, in hours (“Te” in Equation W-32A of this subpart).

§98.236(r)(2)(iii) Total number of meter/regulator runs at above grade metering-regulating stations that 

are not above grade transmission-distribution transfer stations (“CountMR” in Equation 

W-32B of this subpart).

§98.236(r)(2)(iv) Average estimated time that each meter/regulator run at above grade meteringregulating stations that are not above grade transmission-distribution transfer stations 

was operational in the calendar year, in hours per meter/regulator run (“Tw,avg” in 

Equation W-32B of this subpart).

A-5
Table A-1. List of New and Revised Inputs to Emission Equations

Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element

EOR Injection Pumps

§98.236(w)(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” 

in Equation W-37 of this subpart).

§98.236(w)(7) Mass fraction of CO2 in critical phase EOR injection gas (“GHGCO2” in Equation W-37 

of this subpart).

Onshore Natural Gas Processing

§98.236(aa)(3)(v) For natural gas processing, the average mole fraction of CH4 in natural gas received.

§98.236(aa)(3)(vi) For natural gas processing, the average mole fraction of CO2 in natural gas received.

A-6