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 Input s to Emission Equations

Affected by the “2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems”

In the rulemaking titled “Revisions and Confidentia lity 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 reporti ng requirements, including requiring two new industry segments to begin reporting GHG emissi ons, and requiring an existing segment to begin reporting emissions from an additional emissi on source. Specifically, facilities in the Onshore Petroleum and Natural Gas Gathering and Boo sting segment and in the Onshore Natural Gas Transmission Pipeline segment will begin report ing GHG emissions. Facilities in the Onshore Petroleum and Natural Gas Production segmen t will also begin reporting emissions from completions and workovers of hydraulically fra ctured oil wells (previously subpart W only required reporting of emissions from completions an d workovers of gas wells).

These new reporting requirements require the report ing of data elements that are inputs to emission equations for new industry segments (the O nshore Petroleum and Natural Gas Gathering and Boosting segment and the Onshore Natu ral Gas Transmission Pipeline segment) and for a new emission source in an existing segmen t (hydraulically fractured oil wells in the Onshore Petroleum and Natural Gas Production segmen t). 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 co ncerns for these data elements. We followed the same steps set forth in a supporting memorandum 2 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 pub licly 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 Equ ations,” Docket Item No. EPA-HQ-OAR-2010-0929-0037.
3 See rulemaking titled “Change to the Reporting Dat e for Certain Data Elements Required Under the Mand atory Reporting of Greenhouse Gases Rule” (76 FR 53057, A ugust 25, 2011).2 • Step 2: For inputs that are not publicly available, evaluate whether release of the information is likely to result in substantial comp etitive harm.

• Step 3: For inputs that are likely to cause substan tial competitive harm if disclosed, evaluate potential alternative calculation methods.

• Step 4: For inputs that are likely to cause substan tial 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 revie wed included the following:

• Department of Energy, Energy Information Administra tion – www.eia.gov

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

• Department of Transportation, Pipeline and Hazardou s 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 numbe r of reporters represented by the data, the age of the data, and frequency of availability. Alt hough we were able to locate some data that were similar to some of the new inputs, we were una ble 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 fo r each industry segment affected by the proposal and the new inputs to determine whethe r disclosure concerns existed. We focused on the market structure of each industry segment be cause the structure of the market in which a3

reporter does business has a significant impact on the ability of a competitor to use the reported information to gain competitive advantage. Typicall y, 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 cond ucted a qualitative analysis of the market structure for each of the affected industry segment s and assessed potential concerns for each industry segment. The results of our analysis for e ach segment are summarized below.

Onshore Petroleum and Natural Gas Production Segmen t. The onshore petroleum and natural gas production segment covers emissions rel ated to onshore production wellheads. The market structure for petroleum was considered separ ately from natural gas for this segment for the impacts related to the reporting of data elemen ts for natural gas emissions from hydraulically fractured oil wells.

Onshore petroleum production is a regionally concen trated 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 forma tion when lease prices have not stabilized and operators are taking risks by drilling explorat ory wells in formations that do not have proven production records. After several wells have been d rilled in an area, information about production becomes publicly available and the advan tage 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 fr om the well. Although this could pose a potential data sensitivity with respect to explorat ion wells, for most exploratory wells this issue is addressed by the fact that onshore production da ta is reported at a sub-basin level, as defined by county boundaries, and which is a large enough s cale that disclosure of the data collected under subpart W would not reveal any proprietary in formation about the facility or cost to do business. However, for two specific types of explor atory wells, delineation wells and wildcat wells, in specific cases discussed below, early pub lic disclosure of six “inputs to emission equations” data elements could reveal the productiv ity of the oil wells and therefore result in loss of investment value. The six “inputs to emission eq uations” data elements are:

• For oil well completions or workovers with hydrauli c 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 quantit ies are present to enable separation (sum of “T p,i ” values used in Equation W-10A) (40 CFR 98.236(g)( 5)(i));

• For oil well completions or workovers with hydrauli c fracturing in a sub-basin and well type combination category, the cumulative flow back time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T p,s ” values used in Equation W-10A) (40 CFR 98.236(g)(5)(i));4 • For oil well completions or workovers with hydrauli c fracturing in a sub-basin and well type combination category, the flowback rate f or the measured well, in standard cubic feet per hour (40 CFR 98.236(g)(5)(ii));

• For oil well completions or workovers with hydrauli c fracturing in a sub-basin and well type combination category, the gas to oil rati o for the well in standard cubic feet of gas per barrel of oil (“GOR p ” in Equation W-12C);

• For oil well completions or workovers with hydrauli c fracturing in a sub-basin and well type combination category, the volume of oil p roduced during the first 30 days of production after completions of each newly drill ed well or well workover using hydraulic fracturing, in barrels (“V p ” in Equation W-12C); and

• For onshore production storage tanks, the total ann ual gas-liquid separator oil volume that is sent to applicable onshore storage tanks, i n barrels (40 CFR 98.236(j)(1)(iii)).

The specific cases for which early public disclosur e of these six “inputs to emission equations” data elements could reveal the productiv ity of the oil wells and result in loss of investment value are as follows:

• For oil well completions or workovers with hydrauli c fracturing, where wildcat wells and/or delineation wells are the only wells in a su b-basin and well type combination category that can be used for the measurement. Thes e measurements require the use of “representative” wells. If wildcat and/or deline ation 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 wildcatwells 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 explorato ry 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 th e 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 c ases 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 a bout 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 produ ction 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 are5

regionally concentrated, having control over partic ular segments of the pipeline infrastructure. Existing pipeline construction and natural gas tran smission technology and operations development information is generally well-known and understood and technological innovation is mainly in the area of pipeline security. It is p ossible that the limited number of firms and the regional concentration could pose potential data se nsitivity issues. Firms in the onshore natural gas transmission pipeline segment compete with othe rs in their region for shipments of natural gas. Even though there may be only one pipeline tra nsmitting 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 diffe rent endpoints. Such firms could make use of information about their competitors’ throughput qua ntity and/or cost structure to strategically set their prices or other contract terms. Even though t he 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 em ission 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 Boo sting Segment. The onshore petroleum and natural gas gathering and boosting se gment 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 g as processing facilities or, in some cases, transmission pipelines. These agreements are for lo ng periods, lasting from several years to the life of the lease for the producing wells, and establish the prices for gathering services for the lif e of the agreement. Once these agreements are establi shed, information that would be revealed from the “inputs to emission equations” is not like ly to affect the competitive position of the company operating the gathering system because it w ill 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 p roprietary information about the facility or cost to do business.

Step 3 and Step 4

As noted above, disclosure of some of the inputs li sted in Appendix A were determined to have early disclosure concerns in situations whe re the inputs are specific to exploratory wells. The EPA addressed this concern by providing an opti on 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 analysis6

for Steps 1 and 2, the EPA did not proceed to furth er 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 Af fected by the Subpart W 2015 Amendments

Rule Citation Final Data Element Natural Gas Pneumatic Devices (Onshore Petroleum an d Natural Gas Gathering and Boosting) §98.236(b)(1)(i) The total number of devices of eac h 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 (“T t ” in Equation W-1). Natural Gas Pneumatic Pump Venting (Onshore Petrole um 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 Natur al Gas Gathering and Boosting) §98.236(d)(1)(iii) Total feed rate entering the aci d 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 Calcula tion Method 1 or 2 in §98.233(d) is used, annual average volumetric fraction of CO 2 in the vent gas exiting the acid gas removal unit. §98.236(d)(2)(i)(B) For each unit for which Calcula tion 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 CO 2 in the natural gas flowing out of the acid gas removal unit, as specified in E quation 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 CO 2 content in natural gas flowing into the acid gas removal unit, as specifie d in Equation W4A or Equation W-4B.8

Appendix A: List of Inputs to Emission Equations Af fected 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 Equ ation W-4A, reported as either total annual volume of natural g as flow into the acid gas removal unit in cubic feet at actual condi tions; or total annual volume of natural gas flow out of the acid g as removal unit, as specified in Equation W-4B, in cubic feet at act ual 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 Fahren heit. §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 p er 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 mo le 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 ma intenance 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 Gath ering 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 o n best available data. §98.236(e)(1)(iii) Dehydrator feed natural gas wate r content, in pounds per million standard cubic feet. §98.236(e)(1)(iv) Dehydrator outlet natural gas wat er content, in pounds per million standard cubic feet.9

Appendix A: List of Inputs to Emission Equations Af fected by the Subpart W 2015 Amendments

Rule Citation Final Data Element §98.236(e)(1)(v) Dehydrator absorbent circulation p ump 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 opera ting, in hours. §98.236(e)(1)(xi) Temperature of the wet natural ga s, 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 CH 4 in wet natural gas. §98.236(e)(1)(xiv) Mole fraction of CO 2 in wet natural gas. §98.236(e)(2)(i) The total number of glycol dehydra tors with an annual average daily natural gas throughput less than 0.4 million standa rd 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 calcula te annual volumetric total gas emissions for a single well in a sub-basin, the cum ulative gas flowback time, in hours, from when gas is first det ected until sufficient quantities are present to enable separat ion (“T p,i ” in Equation W-10A). §98.236(g)(5)(i) If using Equation W-10A to calcula te annual volumetric total gas emissions for a single well in a sub-basin, the cum ulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (“T p,s ” in Equation W-10A). §98.236(g)(5)(ii) If using Equation W-10A to calcul ate annual volumetric total gas emissions, the measured flowback rate, in standard cubic feet per hour, for each sub-basin (average of “FR s,p ” values used in Equation W-12A). §98.236(g)(5)(iii)(A) If using Equation W-12C to ca lculate 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 (“GOR p ” in Equation W-12C).10

Appendix A: List of Inputs to Emission Equations Af fected by the Subpart W 2015 Amendments

Rule Citation Final Data Element §98.236(g)(5)(iii)(B) If using Equation W-12C to ca lculate the average gas production rate for an oil well, the volume of oil produced du ring the first 30 days of production after completions of each newly drilled well or well workover using hydraulic fracturing, in barrel s (“V p ” in Equation W-12C). §98.236(g)(6)(i) If using Equation W-10B to calcula te annual volumetric total gas emissions, the vented natural gas volume, in standa rd cubic feet, for each well in the sub-basin (“FV s,p ” in Equation W-10B). §98.236(g)(6)(ii) If using Equation W-10B to calcul ate annual volumetric total gas emissions, the flow rate at the beginning of the pe riod 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 (“FR p,i ” in Equation W-10B). Blowdown Vent Stacks (Onshore Natural Gas Transmiss ion Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting) §98.236(i)(1)(i) If you calculated emissions from b lowdown vent stacks by equipment or event type and had only one blowdown f or 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 Equat ion W-14B). Storage Tanks (Onshore Petroleum and Natural Gas Ga thering 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 produc tion and onshore petroleum and natural gas gathering and boosting st orage 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 CO 2 mass, in metric tons CO 2 , that was recovered during the calendar year using a vapor re covery system.11

Appendix A: List of Inputs to Emission Equations Af fected 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 CH 4 mass, in metric tons CH 4 , that was recovered during the calendar year using a vapor re covery 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 thatcontrolled 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 thatcontrolled 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 calend ar year on only one separator in a county, the total time the dump valve on the gasliquid separator did not close properly in the cale ndar year, in hours (“T n ” in Equation W-16). Flare Stacks (Onshore Petroleum and Natural Gas Gat hering and Boosting) §98.236(n)(4) Volume of gas sent to the flare, in standard cubic feet (“V s ” in Equations W-19 and W-20). §98.236(n)(5) Fraction of the feed gas sent to an un-lit flare (“ Z u ” in Equation W19). §98.236(n)(6) Flare combustion efficiency, expressed as the fract ion of gas combusted by a burning flare. §98.236(n)(7) Mole fraction of CH 4 in the feed gas to the flare (“X CH4 ” in Equation W-19). §98.236(n)(8) Mole fraction of CO 2 in the feed gas to the flare (“X CO2 ” in Equation W-20). Centrifugal Compressors (Onshore Petroleum and Natu ral Gas Gathering and Boosting) §98.236(o)(5)(i) Number of centrifugal compressors that have wet sea l oil degassing
vents. Reciprocating Compressors (Onshore Petroleum and Na tural Gas Gathering and Boosting) §98.236(p)(5)(i) Number of reciprocating compressors.12

Appendix A: List of Inputs to Emission Equations Af fected by the Subpart W 2015 Amendments

Rule Citation Final Data Element Equipment Leaks by Population Counts (Onshore Petro leum and Natural Gas Gathering and Boosting) §98.236(r)(1)(ii) Total number of the emission sour ce type at the facility (“Count e ” 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 (“T e ” in Equation W-32A). §98.236(r)(3)(ii)(B) For onshore petroleum and natu ral 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 equi pment 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: exter nal fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fue l combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equival ent of 130 horsepower); or internal fuel combustion units of a ny heat capacity that are compressor-drivers, report for each combus tion unit type and fuel type combination, the quantity of fuel com busted in the calendar year, in thousand standard cubic feet, gal lons, or tons.