MEMORANDUM 

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

From: Alexis McKittrick and Mark DeFigueiredo, EPA/CCD 

Date: February 20, 2014 

Subject: Review for Potential Disclosure Concerns for Proposed New Inputs to Emission 

Equations in the Proposed “Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems” 

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

and Natural Gas Systems” (referred to hereafter as the Subpart W 2014 Proposed Amendments), 

the EPA is proposing a number of changes to the subpart W reporting requirements, including 

the addition of several new data elements. These proposed new data elements include data 

elements that are the actual values used to calculate GHG emissions. As explained in the 

preamble to the proposed rule, we assigned these proposed new 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 memorandum1 accompanying the rule deferring 

the reporting of inputs to emission equations. 2 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. The list of the proposed new 

inputs to emissions equations are provided in Appendix A. 

 

1

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

Docket ID EPA-HQ-OAR-2010-0929. 

2

 See rulemaking, 76 FR 53057, August 25, 2011, titled “Change to the Reporting Date for Certain Data Elements 

Required Under the Mandatory Reporting of Greenhouse Gases Rule.” 
2 

Evaluation of the Proposed 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 proposed 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 

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

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

are exactly the same as the proposed 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 sector affected by the 

proposal3

 and the proposed new inputs to determine whether disclosure concerns existed. We 

focused on the market structure of each industry sector 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, Herfindahl-Hirshman Index values are not 

available for the petroleum and natural gas sectors. As a result, the EPA conducted a qualitative 

analysis of the market structure for each of the affected industry sectors and assessed potential 

concerns for each industry sector. The results of our analysis for each sector are summarized 

below. 

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

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

market structure for petroleum and natural gas was considered separately for this segment. 

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

 

3

 The offshore petroleum and natural gas production sector would not be affected by the proposed amendments. 
3 

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 explorations 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 any early advantage gained by the operator drilling 

exploration wells dissipates. 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, such a concern is ameliorated by the fact that 

onshore production data are reported at a sub-basin level, as defined by county boundaries, 

which is a scale that is large enough that disclosure of the data collected under subpart W would 

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

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 be likely to reveal any proprietary 

information about the facility or cost to do business. 

Natural Gas Processing Sector. Natural gas processors are regionally located close to 

production wellheads. The market itself is large, with roughly 500 firms. These firms are located 

in close proximity to given natural gas plays. We do believe that this regional concentration 

would not pose data sensitivity concerns, because the “inputs to equations” data elements in this 

segment 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 Sector. 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. Although the number of 

firms and the regional concentration could pose data sensitivity issues, we do not believe this is 

an issue for three reasons: (1) existing pipeline construction and natural gas transmission 

technology and operations development information is generally well-known and understood; 

technological innovation is mainly in the area of pipeline security; (2) the rate charged for 

transport is highly regulated, preventing use of the data for strategic price competition; and (3) 

once pipeline and compression are built in a given corridor, there is little incentive for a 

competitor to build additional pipeline and compression along the same route. 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. 

Natural Gas Distribution. Natural gas distributers own and operate the distribution mains 

and services and function as the middle man between transmission lines and end-users. This 
4 

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. 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. 

Liquefied Natural Gas Storage Sector. 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 Sector. 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 
5 

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. 

Step 3 and Step 4 

In light of the above analysis for Steps 1 and 2, the EPA did not proceed to further evaluate the 

proposed “inputs to equations” data elements in subpart W under Steps 3 and 4. 
Appendix A: List of Proposed New Inputs to Emission Equations

Rule Citation Proposed Data Element 

Natural Gas Pneumatic Device Venting 

§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. 

Natural Gas Pneumatic Pump Venting 

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

operational. 

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 (degrees F). 

§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, 

report 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). 
7 

Appendix A: List of Proposed New Inputs to Emission Equations

Rule Citation Proposed Data Element 

§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 absorbant circulation rate (gal/min). 

Well Venting for 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. 

Completions and Workovers with Hydraulic Fracturing 

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

emissions for completions that vent gas to the atmosphere, then you must 

report the vented natural gas volume, in standard cubic feet, for each well 

in the sub-basin. 

Onshore Production Storage Tanks 

§98.236(j)(2)(ii)(B) The number of atmospheric tanks in the sub-basin that did not control 

emissions with flares. 

Transmission Storage Tanks 

§98.236(k)(2)(ii) Measured leak rate (average leak rate from a continuous flow 

measurement device) in standard cubic feet per hour. 

§98.236(k)(2)(iii) Duration of time that venting occurred in hours (may use best available 

data if a continuous flow measurement device was used). 

§98.236(k)(3)(ii) Measured leakage rate (average leak rate from a continuous flow 

measurement device) in standard cubic feet per hour. 

§98.236(k)(3)(iii) Duration of time that flaring occurred in hours (may use best available 

data if a continuous flow measurement device was used). 

§98.236(n)(7) Mole fraction of CH4 in the feed gas to the flare. 

§98.236(n)(8) Mole fraction of CO2 in the feed gas to the flare. 

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

(o)(4) are conducted: For each as found leak measurement performed on 

an emission vent, report the measured flow rate, in standard cubic feet per 

hour. 
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Appendix A: List of Proposed New Inputs to Emission Equations

Rule Citation Proposed Data Element 

§98.236(o)(3)(ii)(B) The compressor mode-source combination reporter emission factor, in 

standard cubic feet per hour. 

§98.236(o)(3)(ii)(C) The total number of compressors measured in the compressor modesource combination in the current reporting year and the preceding two 

reporting years. 

§98.236(o)(4)(ii) Continuous leak measurement data. 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) Centrifugal compressors with wet seal degassing vents in onshore 

petroleum and natural gas production must report the number of 

centrifugal compressors that have wet seal oil degassing vents 

§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, report the compressor mode-source combination reporter 

emission factor, in standard cubic feet per hour (EFm,s 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, report 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, report the measured volume of flow during the 

reporting year, in million standard cubic feet. 

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. 

Enhanced Oil Recovery (EOR) Injection Pump Blowdown 

§98.236(w)(4) Total volume of EOR injection pump system equipment chambers, in 

cubic feet. 

 §98.236(w)(7) Mass fraction of CO2 in critical phase EOR injection gas. 

Natural Gas Processing 

§98.236(aa)(3)(vi) For natural gas processing, the average mole fraction of CH4 in produced 

gas received. 

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

gas received.