MEMORANDUM 

TO: Docket ID No. EPA-HQ-OAR-2014-0831 

FROM: Alexis McKittrick and Mark de Figueiredo, EPA/CCD

DATE: September 23, 2015 

SUBJECT: Review for Potential Disclosure Concerns for Inputs to Emission Equations 

Affected by the “2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems” 

In the rulemaking titled “Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems” (referred to hereafter as the Subpart W 2015 Amendments), the EPA is 

making a number of changes to the subpart W reporting requirements, including requiring two 

new industry segments to begin reporting GHG emissions, and requiring an existing segment to 

begin reporting emissions from an additional emission source. Specifically, facilities in the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment and in the Onshore Natural 

Gas Transmission Pipeline segment will begin reporting GHG emissions. Facilities in the 

Onshore Petroleum and Natural Gas Production segment will also begin reporting emissions 

from completions and workovers of hydraulically fractured oil wells (previously subpart W only 

required reporting of emissions from completions and workovers of gas wells). 

These new reporting requirements require the reporting of data elements that are inputs to 

emission equations for new industry segments (the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment and the Onshore Natural Gas Transmission Pipeline segment) 

and for a new emission source in an existing segment (hydraulically fractured oil wells in the 

Onshore Petroleum and Natural Gas Production segment). As explained in the preambles to the 

proposed and final rules,1 we assigned these data elements 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 rule deferring the 

reporting of inputs to emission equations.3 These steps are the following: 

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

 

1

 See 79 FR 73148, December 9, 2014 for the proposed rule, and see Docket ID. No. EPA-HQ-OAR-2014-0831 for 

the final rule. 

2

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

Docket Item No. EPA-HQ-OAR-2010-0929-0037. 

3

 See rulemaking titled “Change to the Reporting Date for Certain Data Elements Required Under the Mandatory 

Reporting of Greenhouse Gases Rule” (76 FR 53057, August 25, 2011). 
2 

• 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 

inputs to emission equations. The list of the final new inputs to emission equations is provided in 

Appendix A. 

Evaluation of the Subpart W Inputs 

Step 1: Public Availability 

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

are identical to the new 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 

• Publicly available annual reports for companies in the onshore petroleum and natural 

gas gathering and boosting segment. 

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

the same as the new 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 inputs, we were unable to locate any public sources of data that 

are exactly the same as the new inputs, reported by the same reporters, and available on a 

recurring basis. As a result, the EPA proceeded to Step 2 of the evaluation. 

Step 2: Review for Potential Disclosure Concerns 

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

the proposal and the new 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 
3 

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-Hirschman Index to assess market 

concentration. However, Herfindahl-Hirschman Index values are not available for the petroleum 

and natural gas 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 structure for petroleum was considered separately from natural gas for this segment for 

the impacts related to the reporting of data elements for natural gas emissions from hydraulically 

fractured oil wells. 

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 six “inputs to emission 

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

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

• For oil 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 

(sum of “Tp,i” values used in Equation W-10A) (40 CFR 98.236(g)(5)(i)); 

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

well type combination category, the cumulative flowback time, in hours, after 

sufficient quantities of gas are present to enable separation (sum of “Tp,s” values used 

in Equation W-10A) (40 CFR 98.236(g)(5)(i)); 
4 

• For oil 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 (40 CFR 98.236(g)(5)(ii)); 

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

well type combination category, the gas to oil ratio for the well in standard cubic feet 

of gas per barrel of oil (“GORp” in Equation W-12C); 

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

well type combination category, the volume of oil produced during the first 30 days 

of production after completions of each newly drilled well or well workover using 

hydraulic fracturing, in barrels (“Vp” in Equation W-12C); and 

• For onshore production storage tanks, the total annual gas-liquid separator oil volume 

that is sent to applicable onshore storage tanks, in barrels (40 CFR 98.236(j)(1)(iii)). 

The specific cases for which early public disclosure of these six “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 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 onshore production storage tanks, 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 reported for these data elements 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 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 Transmission Pipeline Segment. Natural gas transmission 

pipeline operators transport natural gas from production fields, natural gas processing plants, or 

other transmission compressors through transmission pipelines to natural gas distribution 

pipelines, liquefied natural gas storage facilities, or into underground storage. Firms are 
5 

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

Existing pipeline construction and natural gas transmission technology and operations 

development information is generally well-known and understood and technological innovation 

is mainly in the area of pipeline security. It is possible that the limited number of firms and the 

regional concentration could pose potential data sensitivity issues. Firms in the onshore natural 

gas transmission pipeline 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 potentially to 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. However, only 

one data element is classified as an input to an emission equation: the number of blowdowns in a 

calendar year, if there was only one blowdown for a unique physical volume and equipment or 

event type. The specific information that would be revealed from this data element is not likely 

to reveal information about a firm’s throughput or costs that could be used by competing firms to 

gain a competitive advantage. 

Onshore Petroleum and Natural Gas Gathering and Boosting Segment. The onshore 

petroleum and natural gas gathering and boosting segment is a regionally concentrated segment, 

with gathering lines and other services located in fixed geological basins. Because of the amount 

of fixed assets required to operate in this segment (e.g., gathering lines and boosting stations), 

companies operating in this segment enter into long term agreements with natural gas producers 

to gather natural gas and transport it to natural gas processing facilities or, in some cases, 

transmission pipelines. These agreements are for long periods, lasting from several years to the 

life of the lease for the producing wells, and establish the prices for gathering services for the life 

of the agreement. Once these agreements are established, information that would be revealed 

from the “inputs to emission equations” is not likely to affect the competitive position of the 

company operating the gathering system because it will not reveal information about the cost or 

profitability of providing that gathering service, or about the company’s ability to enter into new 

agreements and expand operations. As a result, the “inputs to emission equations” data elements 

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

cost to do business. 

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 
6 

for Steps 1 and 2, the EPA did not proceed to further evaluate the new “inputs to emission 

equations” data elements in subpart W under Steps 3 and 4. 
7 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

Natural Gas Pneumatic Devices (Onshore Petroleum and Natural Gas Gathering and 

Boosting) 

§98.236(b)(1)(i) The total number of devices of each type, determined according to 

§98.233(a)(1) and (2). 

§98.236(b)(1)(ii)(A) The number of devices of each type reported in paragraph (b)(1)(i) 

of this section that are counted. 

§98.236(b)(1)(ii)(B) The number of devices of each type reported in paragraph (b)(1)(i) 

of this section that are estimated (not counted). 

§98.236(b)(2) 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). 

Natural Gas Pneumatic Pump Venting (Onshore Petroleum and Natural Gas Gathering 

and Boosting) 

§98.236(c)(1) Count of natural gas driven pneumatic pumps. 

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

were operational (“T” in Equation W-2). 

Acid Gas Removal Units (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(d)(1)(iii) 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)(A) For each unit for which Calculation Method 1 or 2 in §98.233(d) is 

used, annual average volumetric fraction of CO2 in the vent gas 

exiting the acid gas removal unit. 

§98.236(d)(2)(i)(B) For each unit for which Calculation Method 1 or 2 in §98.233(d) is 

used, annual volume of gas vented from the acid gas removal unit, in 

cubic feet. 

§98.236(d)(2)(ii)(B) For each unit for which Calculation Method 3 in §98.233(d) is used, 

annual average volumetric fraction of CO2 in the natural gas flowing 

out of the acid gas removal unit, as specified in Equation W-4A or 

Equation W-4B. 

§98.236(d)(2)(ii)(C) For each unit for which Calculation Method 3 in §98.233(d) is used, 

annual average volumetric fraction of CO2 content in natural gas 

flowing into the acid gas removal unit, as specified in Equation W4A or Equation W-4B. 
8 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

§98.236(d)(2)(ii)(D) For each unit for which Calculation Method 3 in §98.233(d) is used, 

the natural gas flow rate used, as specified in Equation W-4A, 

reported as either total annual volume of natural gas flow into the 

acid gas removal unit in cubic feet at actual conditions; or total 

annual volume of natural gas flow out of the acid gas removal unit, 

as specified in Equation W-4B, in cubic feet at actual conditions,. 

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

the solvent pressure, in pounds per square inch. 

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

the solvent temperature, in degrees Fahrenheit. 

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

the solvent circulation rate, in gallons per minute. 

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

the solvent weight, in pounds per gallon. 

Dehydrators (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(e)(1)(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet 

per day, determined by engineering estimate based on best available 

data. 

§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. 
9 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

§98.236(e)(1)(v) Dehydrator absorbent circulation pump type (e.g., natural gas 

pneumatic, air pneumatic, or electric). 

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

§98.236(e)(1)(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol 

(DEG), or ethylene glycol (EG)). 

§98.236(e)(1)(viii) Whether stripper gas is used in dehydrator. 

§98.236(e)(1)(ix) Whether a flash tank separator is used in dehydrator. 

§98.236(e)(1)(x) Total time the dehydrator is operating, in hours. 

§98.236(e)(1)(xi) Temperature of the wet natural gas, in degrees Fahrenheit. 

§98.236(e)(1)(xii) Pressure of the wet natural gas, in pounds per square inch gauge. 

§98.236(e)(1)(xiii) Mole fraction of CH4 in wet natural gas. 

§98.236(e)(1)(xiv) Mole fraction of CO2 in wet natural gas. 

§98.236(e)(2)(i) The total number of glycol dehydrators with an annual average daily 

natural gas throughput less than 0.4 million standard cubic feet per 

day at the facility. 

Completions and Workovers with Hydraulic Fracturing (Onshore Petroleum and Natural 

Gas Production Oil Wells) 

§98.236(g)(5)(i) If using Equation W-10A to calculate annual volumetric total gas 

emissions for a single well in a sub-basin, the cumulative gas 

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

sufficient quantities are present to enable separation (“Tp,i” in 

Equation W-10A). 

§98.236(g)(5)(i) If using Equation W-10A to calculate annual volumetric total gas 

emissions for a single well in a sub-basin, the cumulative flowback 

time, in hours, after sufficient quantities of gas are present to enable 

separation (“Tp,s” in Equation W-10A). 

§98.236(g)(5)(ii) If using Equation W-10A to calculate annual volumetric total gas 

emissions, the measured flowback rate, in standard cubic feet per 

hour, for each sub-basin (average of “FRs,p” values used in Equation 

W-12A). 

§98.236(g)(5)(iii)(A) If using Equation W-12C to calculate the average gas production 

rate for an oil well, the gas to oil ratio for the well in standard cubic 

feet of gas per barrel of oil (“GORp” in Equation W-12C). 
10 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

§98.236(g)(5)(iii)(B) If using Equation W-12C to calculate the average gas production 

rate for an oil well, the volume of oil produced during the first 30 

days of production after completions of each newly drilled well or 

well workover using hydraulic fracturing, in barrels (“Vp” in 

Equation W-12C). 

§98.236(g)(6)(i) If using 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 using Equation W-10B to calculate annual volumetric total gas 

emissions, 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). 

Blowdown Vent Stacks (Onshore Natural Gas Transmission Pipeline and Onshore 

Petroleum and Natural Gas Gathering and Boosting) 

§98.236(i)(1)(i) If you calculated emissions from blowdown vent stacks by 

equipment or event type and had only one blowdown for a unique 

physical volume for an equipment or event type, the total number of 

blowdowns in the calendar year for the equipment or event type 

(equation variable “N” from Equation W-14A or Equation W-14B). 

Storage Tanks (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(j)(1)(iii) If using Calculation Method 1 or 2, the total annual oil volume from 

gas-liquid separators and direct from wells or non-separator 

equipment that is sent to applicable onshore production and onshore 

petroleum and natural gas gathering and boosting storage tanks, in 

barrels. 

§98.236(j)(1)(iv) If using Calculation Method 1 or 2, the average gas-liquid separator 

or non-separator equipment temperature, in degrees Fahrenheit. 

§98.236(j)(1)(v) If using Calculation Method 1 or 2, the average gas-liquid separator 

or non-separator equipment pressure, in pounds per square inch 

gauge. 

§98.236(j)(1)(vi) If using Calculation Method 1 or 2, the average sales oil or 

stabilized oil API gravity, in degrees. 

§98.236(j)(1)(xiii)(B) If using Calculation Method 1 or 2, if any emissions from the 

atmospheric tanks at your facility were controlled with vapor 

recovery systems, the total CO2 mass, in metric tons CO2, that was 

recovered during the calendar year using a vapor recovery system. 
11 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

§98.236(j)(1)(xiii)(C) If using Calculation Method 1 or 2, if any emissions from the 

atmospheric tanks at your facility were controlled with vapor 

recovery systems, the total CH4 mass, in metric tons CH4, that was 

recovered during the calendar year using a vapor recovery system. 

§98.236(j)(2)(i)(B) If using Calculation Method 3, an estimate of the fraction of 

oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this 

section sent to atmospheric tanks in the basin that controlled 

emissions with flares. 

§98.236(j)(2)(i)(C) If using Calculation Method 3, an estimate of the fraction of 

oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this 

section sent to atmospheric tanks in the basin that controlled 

emissions with vapor recovery systems. 

§98.236(j)(3)(ii) If using Calculation Method 1 or 2, if the gas-liquid separator liquid 

dump valve did not close properly during the calendar year on only 

one separator in a county, the total time the dump valve on the gasliquid separator did not close properly in the calendar year, in hours 

(“Tn” in Equation W-16). 

Flare Stacks (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(n)(4) Volume of gas sent to the flare, in standard cubic feet (“Vs” in 

Equations W-19 and W-20). 

§98.236(n)(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W19). 

§98.236(n)(6) Flare combustion efficiency, expressed as the fraction of gas 

combusted by a burning flare. 

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

W-19). 

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

W-20). 

Centrifugal Compressors (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(o)(5)(i) Number of centrifugal compressors that have wet seal oil degassing 

vents. 

Reciprocating Compressors (Onshore Petroleum and Natural Gas Gathering and 

Boosting) 

§98.236(p)(5)(i) Number of reciprocating compressors. 
12 

Appendix A: List of Inputs to Emission Equations Affected by the Subpart W 2015 

Amendments

Rule Citation Final Data Element 

Equipment Leaks by Population Counts (Onshore Petroleum and Natural Gas Gathering 

and Boosting) 

§98.236(r)(1)(ii) Total number of the emission source type at the facility (“Counte” in 

Equation W-32A). 

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

operational in the calendar year, in hours (“Te” in Equation W-32A).

§98.236(r)(3)(ii)(B) For onshore petroleum and natural gas gathering and boosting, for 

each major equipment type, production type (i.e., natural gas or 

crude oil), and geographic location combination in Table W-1B of 

this subpart, if the facility does contain the equipment type, the 

count of the major equipment type. 

Combustion Equipment (Onshore Petroleum and Natural Gas Gathering and Boosting) 

§98.236(z)(2)(iii) If your facility contains: external fuel combustion units with a rated 

heat capacity greater than 5 mmBtu/hr; internal fuel combustion 

units that are not compressor-drivers, with a rated heat capacity 

greater than 1 million Btu per hour (or the equivalent of 130 

horsepower); or internal fuel combustion units of any heat capacity 

that are compressor-drivers, report for each combustion unit type 

and fuel type combination, the quantity of fuel combusted in the 

calendar year, in thousand standard cubic feet, gallons, or tons.