MEMORANDUM

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

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

DATE: November 13, 2014

SUBJECT: Review for Potential Disclosure Concerns for Input s to Emission Equations

Affected by the Proposed “2015 Revisions and Confid entiality Determinations for Petroleum and Natural Gas Systems”

In the proposed rulemaking titled “Revisions and Co nfidentiality Determinations for Petroleum and Natural Gas Systems” (referred to her eafter as the Subpart W 2015 Proposed Amendments), the EPA is proposing a number of chang es to the subpart W reporting requirements, including that two new industry segme nts begin reporting GHG emissions, and that an existing segment begin reporting emissions from an additional emission source. The EPA is proposing that facilities in the Onshore Petrole um and Natural Gas Gathering and Boosting segment and in the Onshore Natural Gas Transmission Pipeline segment begin reporting GHG emissions. The EPA is also proposing that facilitie s in the Onshore Petroleum and Natural Gas Production segment begin reporting emissions from c ompletions and workovers of hydraulically fractured oil wells (currently subpart W only requi res reporting of emissions from completions and workovers of gas wells).

These proposed new reporting requirements would req uire the reporting of data elements that are inputs to emissions equations for new indu stry 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 preamble to the proposed rule, we assigned these da ta elements to the Inputs to Emission Equations data category and evaluated potential dis closure concerns for these data elements. We followed the same steps set forth in a supporting m emorandum 1 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 pub licly available.

• Step 2: For inputs that are not publicly available, evaluate whether release of the information is likely to result in substantial comp etitive harm.

1 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.

2 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 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. The list of the inputs to emissions equations are provided in Appendix A.

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 sour ces reviewed 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 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 wer e unable to locate any public sources of data that are exactly the same as the proposed new input s, reported by the same reporters, and available on a recurring basis. As a result, the EP A 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 proposed new inputs to determi ne whether disclosure concerns existed. We focused on the market structure of each industry se gment because the structure of the market in which a reporter does business has a significant im pact 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 t ools such as the Herfindahl-Hirschman Index3

to assess market concentration. However, Herfindahl -Hirschman Index values are not available for the petroleum and natural gas segments. As a re sult, the EPA conducted a qualitative analysis of the market structure for each of the affected in dustry segments and assessed potential concerns for each industry segment. The results of our analy sis for each 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 i s a regionally concentrated market, with wells located in fixed geological formations. Decisions o n where to drill wells may be based on proprietary information during the early developmen t of a formation when lease prices have not stabilized and operators are taking risks by drilli ng 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 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 four “inputs to equations” data elements could reveal the productivity of the wells and therefore result in loss of investment value. The six “inputs to equations” data elements are:

• For oil well completions or workovers with hydrauli c fracturing, the cumulative gas flowback time, in hours, for each sub-basin, from w hen gas is first detected until sufficient quantities are present to enable separat ion (40 CFR 98.236(g)(5)(i));

• For oil well completions or workovers with hydrauli c fracturing, the cumulative flowback time, in hours, for each sub-basin, after sufficient quantities of gas are present to enable separation (40 CFR 98.236(g)(5)(i ));

• For oil well completions or workovers with hydrauli c fracturing, the measured flowback rate, in standard cubic feet per hour, for each sub-basin (40 CFR 98.236(g)(5)(ii)); 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)(v)).4

The specific cases for which early public disclosur e of these four “inputs to equations” data elements could reveal the productivity of the 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 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 informa tion 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 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 four 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 the EPA did not proceed to evaluate each “input to equation” data element i n 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 are 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 issions equation: the number of blowdowns in a calendar year, if there was only one blowdown for a unique physical volume and equipment or5

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 esta blish 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 emissions equations” is not lik ely 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 equations” data elements in this segment would not be likely to reveal any proprieta ry 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 proposed 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 p roceed to further evaluate the proposed “inputs to equations” data elements in subpart W un der Steps 3 and 4.6

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed 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 (a)(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 of this subpart). 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)(3) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W-2 of this subpa rt). 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 Methodology 1 or 2 in §98.233(d) is used, annual average volumetric fract ion 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 Methodology 1 or 2 in §98.233(d) is used, annual volume of gas vented fro m the acid gas removal unit, in cubic feet. §98.236(d)(2)(ii)(B) For each unit for which Calculation Methodology 3 i n §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 Equation W4A or Equation W-4B of this subpart. §98.236(d)(2)(ii)(C) For each unit for which Calculation Methodology 3 i n §98.233(d) is used, annual average volumetric fraction of CO 2 content in natural gas flowing into the acid gas removal unit, as spec ified in Equation W-4A or Equation W-4B of this subpart.7

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed Data Element §98.236(d)(2)(ii)(D) For each unit for which Calculation Methodology 3 i n §98.233(d) is used, the natural gas flow rate used, as specified in Equation W-4A of this subpart, reported as either total annual volum e of natural gas flow into the acid gas removal unit in cubic feet at act ual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W-4B of this subpart , in cubic feet at actual conditions,. §98.236(d)(2)(iii)(B) For each unit for which Calculation Methodology 4 i n §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 i n §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 i n §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 i n §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 i n §98.233(d) is used, the acid gas content of the outlet natural ga s, in mole percent. §98.236(d)(2)(iii)(G) For each unit for which Calculation Methodology 4 i n §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 i n §98.233(d) is used, the exit temperature of the natural gas, in d egrees Fahrenheit. §98.236(d)(2)(iii)(I) For each unit for which Calculation Methodology 4 i n §98.233(d) is used, the solvent pressure, in pounds per square in ch. §98.236(d)(2)(iii)(J) For each unit for which Calculation Methodology 4 i n §98.233(d) is used, the solvent temperature, in degrees Fahrenhei t. §98.236(d)(2)(iii)(K) For each unit for which Calculation Methodology 4 i n §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 Methodology 4 i n §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)(iii) 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)(iv) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. §98.236(e)(1)(v) Dehydrator outlet natural gas wate r content, in pounds per million standard cubic feet.8

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed Data Element §98.236(e)(1)(vi) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or electric). §98.236(e)(1)(vii) Dehydrator absorbent circulation rate, in gallons per minute. §98.236(e)(1)(viii) Type of absorbent (e.g., trieth ylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)). §98.236(e)(1)(ix) Whether stripper gas is used in d ehydrator. §98.236(e)(1)(x) Whether a flash tank separator is used in dehydrator. §98.236(e)(1)(xi) Total time the dehydrator is oper ating, in hours. §98.236(e)(1)(xii) Temperature of the wet natural g as, in degrees Fahrenheit. §98.236(e)(1)(xiii) Pressure of the wet natural gas , in pounds per square inch gauge. §98.236(e)(1)(xiv) Mole fraction of CH 4 in wet natural gas. §98.236(e)(1)(xv) Mole fraction of CO 2 in wet natural gas. §98.236(e)(2)(i) The total number of glycol dehydra tors at the facility with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day. Completions and Workovers with Hydraulic Fracturing (Onshore Petroleum and Natural Gas Production Oil Wells) §98.236(g)(5)(i) If you used Equation W-10A to calc ulate annual volumetric total gas emissions for a single well, the cumulative gas flo wback time, in hours, from when gas is first detected until suffic ient quantities are present to enable separation (sum of “T p,i ” values used in Equation W-10A). §98.236(g)(5)(i) If you used Equation W-10A to calc ulate annual volumetric total gas emissions for a single well, the cumulative flowbac k time, in hours, after sufficient quantities of gas are present to e nable separation (sum of “T p,s ” values used in Equation W-10A). §98.236(g)(5)(ii) If you used Equation W-10A to cal culate 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 in Equation W12A). §98.236(g)(5)(iii)(A) If you used 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 (“GOR p ” in Equation W-12C). §98.236(g)(5)(iii)(B) If you used Equation W-12C to calculate 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).9

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed Data Element §98.236(g)(6)(i) If you used Equation W-10B to calc ulate annual volumetric total gas emissions for completions that vent gas to the atmo sphere, the vented natural gas volume, in standard cubic feet, for eac h well in the subbasin (“FV s,p ” in Equation W-10B). §98.236(g)(6)(ii) If you used Equation W-10B to cal culate annual volumetric total gas emissions for completions that vent gas to the atmo sphere, the flow rate at the beginning of the period of time when su fficient quantities of gas are present to enable separation, in standar d 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 for a uniqu e physical volume for an equipment or event type, the total nu mber of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from Equation W-14A orEquation W14B of this subpart, for all unique physical volume s for the equipment or event type). Storage Tanks (Onshore Petroleum and Natural Gas Ga thering and Boosting) §98.236(j)(1)(v) If using Calculation Method 1 or 2 , the total annual oil volume from gas-liquid separators and direct from wells that is sent to applicable onshore production and onshore petroleum and natura l gas gathering and boosting storage tanks, in barrels. §98.236(j)(1)(vi) If using Calculation Method 1 or 2, the average gas-liquid separator temperature, in degrees Fahrenheit. §98.236(j)(1)(vii) If using Calculation Method 1 or 2, the average gas-liquid separator pressure, in pounds per square inch gauge. §98.236(j)(1)(viii) If using Calculation Method 1 o r 2, the average sales oil or stabilized oil API gravity, in degrees. §98.236(j)(1)(xiv)(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. §98.236(j)(1)(xiv)(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.10

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed Data Element §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 you used Calculation Method 1 or Calculation Method 2, and any gas-liquid separator liquid dump values did not clo se properly during the calendar year, the total time the dump valves o n gas-liquid separators did not close properly in the calendar y ear, in hours (sum of the “T n ” values in Equation W-16 of this subpart). 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 of this subpart). §98.236(n)(5) Fraction of the feed gas sent to an un-lit flare (“ Z u ” in Equation W-19 of this subpart). §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 of this subpart). §98.236(n)(8) Mole fraction of CO 2 in the feed gas to the flare (“X CO2 ” in Equation W-20 of this subpart). 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. 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 of this subpart). §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 of this subpart).11

Appendix A: List of Inputs to Emission Equations Af fected by the Proposed Amendments

Rule Citation Proposed Data Element §98.236(r)(3)(ii)(B) For each major equipment type in natural gas gathering and boosting, production type (i.e., natural gas or crude oil), a nd geographic location combination in Tables W-1B and W-1C of thi s 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)(iv) If your facility contains: extern al 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 equivalent of 1 30 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.