MEMORANDUM

To: Docket # EPA

- HQ

- OAR

- 2011

- 0512

From: Mark d e Figueiredo, EPA/CCD

Date: November 10 , 201 4

Subject: Review for Potential Disclosure Concerns for New and Revised Inputs to Emission Equations in the “Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Final Rule”

In the rulemaking titl ed “ Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems ; Final Rule ” ( hereinafter referred to as the Subpart W 2014 Amendments), the EPA is revising several of the subpart W reporting data elements and addi ng several new reporting data elements. These new and revised data elements include data elements that are the actual values used to calculate GHG emissions. As explained in the preamble s to the proposed and final rule s 1 , we assigned these new and revised inputs to the “ Inputs to Emission Equations ” data category and evaluated potential disclosure concerns for these data elements . We follow ed the same steps set forth in a supporting memorandum 2 accompanying the proposed rule addressing inputs to emission equations that were deferred until 2015

. 3 These steps are the following :

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

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

• Step 3: For inputs that are likely to cause substantial competitive harm if disclosed, evaluate potential alternative calcul ation methods.

• Step 4: For inputs that are likely to cause substantial competitive harm if disclosed, evaluate potential alternative verification methods.

The purpose of this memorandum is to document this evaluation for the final list of new and revised inputs to emissions equations and to explain the reasons for changes in the list since proposal

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

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

- HQ

- OAR

- 2011

- 0512 for the final rule.

2 See memorandum titled “ Process for Evaluating and Potentially Amending Part 98 Inputs to Emission Equations, ” Docket ID No. EPA

- HQ

- OAR

- 2010

- 0929

- 0037

. 3 See 78 FR 55994 , September 11, 2013 for the proposed rule, and see 79 FR 63750, October 24, 2014 for the final rule

.

1

### 1. Changes to the List of Inputs Since Proposal

The list in Append ix A includes 1 7 new and revised inputs that were not o n the list in the proposed memorandum evaluating the inputs to equations for this action , and one input on the proposed list has been removed from the final list.

Seven of the inputs added to the final list in Appendix A were added because we determined while preparing the final amendments package that they are inputs to an emissions equation under certain conditions

. Five of the seven data element s are inputs when the data used in the emission cal culation are from only one well. The inputs that meet this condition are the cumulative gas flowback time used in Equation W

- 10A ( § 98.236(g)(5)(i)), the average daily gas production rate for completions without hydraulic fracturing used in Equation W

- 13B w ith and without flaring ( § 98.236(h)(1)(iv) and (h)(2)(iv) , respectively ), the volume of oil produced during periods in which associated gas was vented or flared as used in Equation W

- 18 ( § 98.236(m)(5)), and the total volume of associated gas sent to sales during time periods in which associated gas was vented or flared as used in Equation W

- 18 ( § 98.236(m)(6)). Additionally, the total number of blowdowns is an input to Equation 14A or 14B when blowdowns occurred for only one unique physical volume for a part icular equipment type (§98.236(i)(1)(i)), and the time gas

- liquid separator dump valves did not close properly is an input to Equation W

- 16 when only one separator had a dump valve that did not close properly (§98.236(j)(3)(ii)). In situations where data a re not inputs to emission equations , these data elements are assigned to the “Unit/Process Operating Characteristics that are Not Inputs to Emission Equations” data category. Thus, confidentiality determinations were developed for these data elements as di scussed in the memorandum title d “Final Data Category Assignments and Confidentiality Determinations for Data Elements (excluding inputs to emission equations) in the “Greenhouse Gas Reporting Rule : 2014 Revisions and Confidentiality Determinations for Pet roleum and Natural Gas Systems; Final Rule” (see Docket I d. No. EPA

- HQ

- OAR

- 2011

- 0512). Four of the inputs added to the final list in Appendix A were improperly assigned to the “Unit/Process Operating Characteristics that are Not Inputs to Emission Equation s” data category for the proposed rule . These data elements are the average flow rate from tested oil wells in barrels of oil per day for the well(s) tested where emissions are not vented to a flare ( § 98.236(l)(1)(iv)) and where emissions are vented to a f lare ( § 98.236(l)(2)(iv)). These data elements are direct inputs to Equation W

- 17A when all of the emissions from tested wells are either vented to atmosphere or vented to a flare. However, in situations where emissions from some tested wells are vented to atmosphere and others are vented to flares, the two average values can be combined with the reported number of tested wells vented to atmosphere and the reported number of tested wells vented to flare to calculate the average oil flow rate that is used in Equation W

- 17A. As a result, the two separately reported oil volumes are effectively inputs. A similar situation applies for the average annual gas production rates when emissions from tested gas wells are either vented to atmosphere or vented to flare ( § 9 8.236(l)(3)(iii) and (l)(4)(iii), respectively); these values are effectively inputs to Equation W

- 17B.

Three of the inputs added to the final list in Appendix A were included in the reporting requirements i n the proposed rule, but they were inadvertently not assigned to a data category in the analysis at proposal

. For the final rule, t he three data elements have been assigned to the inputs to emission equations data category because they are used directly in equations. These inputs are the measured flow ra te for as found measurements of reciprocating compressors,

2which is an input in Equation W

- 28 ( § 98.236(p)(3)(i)(D)); the total number of meter/regulator runs at above grade transmission

- distribution transfer stations, which is an input in Equation W

32B ( § 98.236(r)(2)(iii)); and the average estimated time that each meter/regulator run at above grade metering

- regulating stations that are not above grade transmission

- distribution transfer stations was operational, which is an input in Equation W

- 32B ( § 98.236( r)(2)(iv)). One additional element that was inadvert ently omitted from the reporting re quirements in the proposed rule has also been assigned to the Inputs to Emissions Equations data category for the final rule . This input is the measured vented or flared flowback rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation that is used in Equation W

- 10B ( § 98.236(g)(6)(ii)).
In consideration of comments, the EPA has revised the method in the final rule for calculating equipment leak emissions from meter/regulator runs at above grade transmission

distribution transfer stations. The revised method requires annual estimation of emissions from all meter/regulator runs at the facility, not just the meter/regulato r runs that were surveyed in the calendar year. Thus, we also added requirements in the final rule to report the total number of meter/regulator runs at the facility and the estimated time that each meter/regulator run was operational in the calendar year (§98.236(q)(3)(ix)(A) and (q)(3)(ix)(B)) . These data elements are inputs to Equation W

- 32B. The number of atmospheric tanks in the sub

- basin for which emissions were calculated using Calculation Method 3 and that did not control emissions with flares is no t an input; thus, this data element was removed from the final list in Appendix A (§98.236(j)(2)(ii)(B))

.


### 2. Evaluation of the Proposed Subpart W Inputs

2.1 Step 1: Public Availability In the first step, we conducted a literature search to identify publicly avail able data that are identical to the new and revised inputs. Data sources reviewed included the following:

• Department of Energy, Energy Information Administration

- www.eia.gov

• Department of Energy, Federal Energy Regulat ory Commission

– www.ferc.gov

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

- www.phmsa.dot.gov

• American Petroleum Ins titute: Industry Statistics

- www.api.org/statistics

• American Gas Association

- www.aga.org

• Railroad Commission of Texas

- www.rrc.state.tx.us/data/index.php

Public data identified during our literature search were evaluated on whether they were the same as the new and revised inputs by considering the number of reporters represented by the data, the age of the data, a nd frequency of availability. Although we were able to locate some data that were similar to some of the new and revised inputs, we were unable to locate any public sources of data that are exactly the same as the new and revised inputs, reported by the same reporters, and available on a recurring basis. As a result, the EPA proceeded to Step 2 of the evaluation.

32.2 Step 2: Review for Potential Disclosure Concerns In Step 2, we examined both the market structure for each industry segment affected by the fi nal subpart W 2014 amendments 4 and the new and revised inputs to determine whether disclosure concerns existed. We focused on the market structure of each industry segment because the structure of the market in which a reporter does business has a signific ant 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 conce ntration. However, Herfindahl

Hirshman Index values are not available for the petroleum and natural gas industry segments . As a result, the EPA conducted a qualitative analysis of the market structure for each of the affected industry segments and assessed potential concerns for each industry segment . The results of our analysis for each segment are summarized below.

Onshore Petroleum and Natural Gas Production Segment

. The onshore petroleum and natural gas production segment covers emissions related to ons hore production wellheads. The market structure s for petroleum and natural gas were considered separately for this segment. Onshore petroleum production is a regionally concentrated market, with wells located in fixed geological formations. Decisions on wh ere 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 explorat ory wells in formations that do not have proven production recor ds. After several wells have been drilled in an area, information about production becomes publicly available and the adva n tage incurred by the operator drilling exploration wells is lost

. However, once a well has been drilled, decisions to produce are bas ed 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 repor ted 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 spec ific types of exploratory wells, delineation wells and wildcat wells, in specific cases discussed below, early public disclosure of four “inputs to emission equations” data elements could reveal the productivity of the oil wells and therefore result in loss of investment value. The four “inputs to emission equations” data elements are:

• For oil well testing, i f oil well testing is performed where emissions are not vented to a flare, the average flow rate in barrels of oil per day for well(s) tested ( §98. 236( l )( 1 )(i v ));

• For oil well testing, i f oil well testing is performed where emissions are vented to a flare, the average flow rate in barrels of oil per day for well(s) tested (§98.236(l)(2)(iv));

• For associated gas venting a nd flaring, v olume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (§98.236(m)(5)); and

4 The offshore petrol eum and natural gas production industry segment was not examined in this analysis because none of the data elements for this industry segment are assigned to the “Inputs to Emission Equations” data category

.

4• For associated gas venting and flaring, t otal volume of associated gas sent to sales, in standar d cubic feet, in the calendar year during time periods in which associated gas was vented or flared ( § 98.236( m)(6 )).

The specific cases for which early public disclosure of these four “inputs to emission equations” data elements could reveal the productivi ty of the oil wells and result in loss of investment value are as follows:

• For oil well testing

, where wildcat wells and/or delineation wells are the only wells in a sub

- basin that are tested . If wildcat and/or delineation wells are the only wells that are tested , then the inputs could reveal information on the productivity of the well.

• For associated gas venting and flaring , where wildcat wells and/or delineation wells are the only wells in a sub

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

- basin, then the volumes of oil produced and associated gas sent to sales would represent volumes of wildcat wells and/or exploratory wells exclusively, which could reveal information o n the productivity of the well.

Delaying reporting of these data for two reporting years would be sufficient time for reporters to thoroughly conduct an assessment of the well, after which the data could be reported and made publicly available. Besides the need for a two

- year delay for the four data elements associated with exploratory wells in the specific cases described above, the likelihood of harm can be characterized for all information collected for this segment and would not be likely to reveal any pro prietary information or information about the cost to do business . Thus, the EPA did not proceed to evaluate each “input to emission equation s ” data element in this segment. The onshore natural gas production market overlaps many of the geological formations of petroleum production. Furthermore, the market itself is structured the same, with a large number of operators within each formation. Like onshore oil production, disclo sure of data for onshore natural gas production at the sub

- basin level would not reveal any proprietary information about the facility or cost to do business , except for two specific types of exploratory wells, delineation wells and wildcat wells, in the s pecific cases discussed below . In these specific cases , early public disclosure of six “inputs to emission equations” data elements could reveal the productivity of the gas wells and therefore result in loss of investment value. The six “inputs to emission equations” data elements are:

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

- basin and well type combination category

, the cumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities are pr esent to enable separation, and the cumulative flowback time, in hours, after sufficient quantities are present to enable separation (sum of “T p,i ” and sum of “T p,s ” values used in Equation W

- 10A) (§98.236( g)(5)(i ));

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

- basin and well type combination category , the flowback rate for the measured well, in standard cubic feet per hour (§98.236( g)(5)(ii ));

• For each sub

- basin with gas well completions without hydraulic fracturing and without flaring, the average daily gas production rate for all completions without hydraulic

5fracturing in the sub

- basin without flaring, in standard cubic feet per hour (§98.236( h)(1)(iv ));

• For each sub

- basin with gas well completions without hydraulic fracturin g and with flaring, the average daily gas production rate for all completions without hydraulic fracturing in the sub

- basin with flaring, in standard cubic feet per hour (§98.236(h)(2)(iv));

• For gas well testing, if gas well testing is performed where emi ssions are not vented to a flare, the average annual production rate in actual cubic feet per day for well(s) tested (§98.236(l)(3)(iii)); and

• For gas well testing, if gas well testing is performed where emissions are vented to a flare, the average annual production rate in actual cubic feet per day for well(s) tested (§98.236(l)(4)(iii) ).

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

• For gas well completions or workovers with hydraulic fracturing, where wildcat wells and/or delineation wells are the only wells in a sub

- basin and well type combination category that can be used for the measurement. These measurements require the use of “representative” wells. If wildcat and/or delineation wells are the only wells that can be used for measurement of these data, then the inputs could reveal information on the produ ctivity of the well

.

• For gas well completions without hydraulic fracturing, where wildcat wells and/or delineation wells are the only wells in a sub

- basin that can be used the measurement. If wildcat and/or delineation wells are the only wells that can be used for measurement of these data, then the inputs could reveal information on the productivity of the well

.

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

- basin that are tested. If wildcat and/or delineati on wells are the only wells that are tested , then the inputs could reveal information on the productivity of the well

. As for oil wells, delaying reporting of these data for two reporting years would be sufficient time for reporters to thoroughly conduct a n 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 ca n be characterized for all information collected for this segment and would not be likely to reveal any pro prietary information or information about the cost to do business

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

Onshore Natural Gas Processing Segment

. Natural gas processors are regionally located close to production wellheads. The segment itself is large, with roughly 500 plants and almost 250 owner companies . These plants are located in c lose proximity to given natural gas plays

, generally accepting input gas via pipeline, and competing in regional markets

. There is market concentration, even at the national level: the top 10% of owner companies control 64% of the processing capacity, acco rding to EIA’s 2012 processing capacity database. Thus, firms are

6aware of their competitors and release of data revealing production costs

, operating efficiency , or market share could cause competitive harm

. Data elements of potential concern include the quantity of natural gas received, the quantity of residue gas leaving the plant, and the quantities of individual NGLs produced. These data elements are not inputs to equation s . Thus, w e believe that th e regional concentration of firms in this segment woul d not pose data sensitivity concerns, because the “inputs to equations” data elements in this segment listed in Appendix would not be likely to reveal any proprietary information about the facility, cost of natural gas, or cost to do business

. Natural Gas Transmission Compression Segment

. Natural gas transmission compression operators transport natural gas from processors to end users. Firms are regionally concentrated, having control over particular segments of the pipeline infrastructure. The limited

num ber of firms and the regional concentration could pose data sensitivity issues

. Firms in the natural gas pipeline transmission segment compete with others in their region for shipments of natural gas. Even though there may be only one pipeline transmitting natural gas from one location to another, competition exists between firms that wish to accept shipments of natural gas within a given region for transmission to potentially different endpoints. Such firms could make use of information about their competi tors’ throughput quantity and/or cost structure to strategically set their prices or other contract terms. Even though the market is regulated by FERC, actual contract prices may be set at levels below the FERC

- mandated maximum tariff. As a result, through put or other data elements that can be used to estimate throughput should be evaluated to determine if they are available elsewhere, and if not, whether they would reveal information about a firm’s throughput or costs that could be used by competing firms to gain a competitive advantage. Such data elements are not “inputs to equations”. Thus, the data elements listed in Appendix A would not be likely to reveal any
pro prietary information or information about the cost to do business for facilities in this in dustry segment

. Natural Gas Distribution Segment

. Natural gas distributers own and operate the distribution mains and services and function as the middle man between transmission lines and end

- users. This market is regionally located with distributers havi ng 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 giv en regions prevents competitors’ use of the data for strategic purposes. As a result, the “inputs to equations” data elements in this segment would not be likely
to reveal any proprietary information about the facility or cost to do business. Underground Natural Gas Storage Segment

. Underground natural gas storage is used to smooth out volatility in consumption and use of natural gas. The market is regional; facilities are located either near major distribution centers or near oil and gas fields. Even with the regional market structure, competitors are not known to engage in strategic competition in building storage facilities. First, facilities are built in response to other upstream factors, such as increased gas supply coming to distributors, not to unde rmine 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 an d 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.

7Liquefied Natural Gas Storage Segment

. Liquefied n atural g as (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 occ urs in response to increase sup p ly 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 fa cility or cost to do business. Liquefied Natural Gas Import/Export Segment

. Currently the U.S. has only 12 LNG import terminals and one LNG export terminal. There are nine onshore import terminals and three offshore import terminals. LNG technology is not proprietary. The technology is relatively simple and has been available for many years. The market is regional and small with import terminals located along the Gulf and East coasts. Although there are a small number of facilities that import and/or expor t 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. Functiona lly, 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 natur al gas are publicly available and the building of new import and export terminals is limited by capital and permitting, not by market
structure. R elease of information about import/export terminals would not be likely to change the operations of other firm s in the market. As a result, the “inputs to equations” data elements in this segment would not be likely to reveal any proprietary information about the facility or cost to do business.

2.3 Step 3 and Step 4 As noted above, disclosure of some of the inputs l isted 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 the s e inputs for up to two years. In light of this option and the above analysis for Steps 1 and 2, the EPA did not proceed to further evaluate the “inputs to equations” data elements in s ubpart W under Steps 3 and 4

.

8

## Appendix A

List of New and Revised Inputs to Emission Equations Affected by t he Subpart W 2014 AmendmentsTable A

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

Rule Citation Final Data Element Natural Gas Pneumatic Device Venting
§98 .236(b)(2) For each type of pneumatic device, the estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“T t ” in Equation W

- 1 of this subpart)

. Natural Gas Pneumatic Pump Venting §98. 236(c)(2) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W

- 2 of this subpart)

. Acid Gas Removal
§98. 236(d)(1)(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year.
§98. 236(d)(2)(i)(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.
§98. 236(d)(2)(iii)(B) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the natural gas feed temperature , in degrees F ahrenheit

. §98. 236(d)(2)(iii)(C) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the natural gas feed pressure, in pounds per square inch.
§98. 236(d)(2)(iii)(D) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the natural gas flow rate, in standard cubic feet per minute.
§98. 236(d)(2)(iii)(E) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the acid gas content of the feed natural gas, in mole percent.
§98. 236(d)(2)(iii)(F) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the acid gas content of the outlet natural gas, in mole percent.
§98. 236(d)(2)(iii)(G) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the unit operating hours, excluding downtime for maintenance or standby, in hours per year.
§98. 236(d)(2)(iii)(H) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, the exit temperature of the natural gas, in degrees Fahrenheit.
§98. 236(d)(2)(iii)(I) For each unit for which Ca lculation 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) F or each unit for which Calculation Methodology 4 in §98. 233(d) is used, solvent circulation rate, in gallons per minute

. §98. 236(d)(2)(iii)(L) For each unit for which Calculation Methodology 4 in §98. 233(d) is used, solvent weight, in pounds per gallon. Dehydrators §98. 236(e)(1)(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.
§98. 236(e)(1)(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.
§98. 236(e)(1)(vi) Dehydrator absorbent circulation rate , in gal lons per min ute

. Liquids Unloading §98. 236(f)(1)(vi) Cumulative amount of time wells were vented (sum of “T p ” from Equation W

- 7A or W

- 7B of this subpart)

, in hours.

A

- 2Table A

- 1. List of New and Revised Inputs to Emission Equations Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element

Gas Well Completions and Workovers with Hydraulic Fracturing §98.236(g)(5)(i) 5 If you used Equation W

- 10A to calculate annual volumetric total gas emissions , the cumulative gas flowback time , in hours, from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback ti me, in hours

, after sufficient quantities of gas are present to enable separa tion ( sum of “T p,i ” and sum of “T p,s ” values used in Equation W

- 10A )

. §98. 236(g)(6) (i) If you used Equation W

- 10B to calculate annual volumetric total gas emissions, the vented natural gas volume, in standard cubic feet, for each well in the sub

- basin (“ FV s,p ” in Equation W

- 10B)

. §98.236(g)(6)(ii) If you used Equation W

- 10B to calculate annual volumetric total gas emissions for completions or workovers that vent gas to the atmosphere or flare, the flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour, for each well in the sub

- basin (“FR p,i ” in Equation W

- 10B). Gas Well Completions and Workovers without Hydraulic Fracturing §98.236(h)(1)(iv) 6 The average daily gas production rate for all completions without hydraulic fracturing in the sub

- basin without flaring, in standard cubic feet per hour (average of all “Vp” used in Equation W

- 13B). §98.236(h)(2)(iv) 7 The average daily gas production rate for all completions without hydraulic fracturing in the sub

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

- 13B).

Blowdown Vent Stacks §98.236(i)(1)(i) 8 Total number of blowdowns in the calendar year for the equipment or event type (sum of equation variable “N” from Equation W

- 14A or Equation W

- 14B of this subpart, for all unique physical volumes for the equipment or event type).

Onshore Production Storage Tanks §98.236(j)(3)(ii) 9 If any of the gas

- liquid separator dump valves did not close properly during the reporting year, the total time, in hours, the dump valves did not close properly (sum of the “T n ” values used in Equation W

- 16). Transmission Storage Tanks §98.236(k)(2)(ii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and the vent stack vented directly to the atmosphere during the calendar year, the measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.

5 These data elements are inputs only when repor ted information is based on data for a single well.

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

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

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

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

- liquid sepa rator with a dump valve that did not close properly.

A

- 3Table A

- 1. List of New and Revised Inputs to Emission Equations Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element §98.236(k)(2)(iii) If scrubber dump valve leakage occurred for a transmission storage tank vent stack and the vent stack vented directly to the atmosphere during the calendar year, the duration of time that the leak is counted as having occurred, in hours, as determined in §98.233(k)(3) (may use best available data if a continuous flow measurement device was used). §98.236(k)(3)(ii) If scrubber dump valve leakage occurred for a transmi ssion storage tank vent stack and the vent stack vented to a flare during the calendar year, the measured leakage rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour. §98.236(k)(3)(iii) If scrubber dump valv e leakage occurred for a transmission storage tank vent stack and the vent stack vented to a flare during the calendar year, the duration of time that flaring occurred in hours as defined in §98.233(k)(3) (may use best available data if a continuous flow m easurement device was used). Well Testing §98.236(l)(1)(iv) If oil well testing is performed where emissions are not vented to a flare, the average flow rate for well(s) tested, in barrels of oil per day. §98.236(l)(2)(iv) If oil well testing is performed where emissions are vented to a flare, the average flow rate for well(s) tested, in barrels of oil per day. §98.236(l)(3)(iii) If gas well testing is performed where emissions are not vented to a flare, the average annual production rate for well(s) tested, in actual cubic feet per day. §98.236(l)(4)(iii) If gas well testing is performed where emissions are vented to a flare, the average annual production rate for well(s) tested, in actual cubic feet per day.

Associated Natural Gas §98.236(m)(5) 10 Volume of oil produced, in barrels, in the calendar year during time periods in which associated gas was vented or flared (the sum of “V p,q ” used in Equation W

- 18 of this subpart)

. §98.236(m)(6) 11 Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of “SG” values used in Equation W

- 18 of §98.233(m))

. Flare Stacks §98.236(n)(7) Mole frac tion 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 §98.236(o)(3)(i)(D) If the measurement methods specified in paragraphs §98.233(o)(2) or (o)(4) are conducted, then for each as found measurement performed on a leak or vent, the measured flow rate, in standard cubic feet per hour. §98.236(o)(3)(ii)(B) For each compressor mode

- source combination where a reporter emission factor as calculated in Equation W

- 23 was used to calculate emissions in Equation W

- 21, the compressor mode

- source combination reporter emission factor, in standard cubic feet per hour (“EF s,m ” in Equation W

- 23).

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

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

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- 4Table A

- 1. List of New and Revised Inputs to Emission Equations Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element §98. 236(o)(3)(ii)(C) For each compressor mode

- source combination where a reporter emission factor as calculated in Equation W

- 23 was used to calculate emissions in Equation W

- 21, t he total number of compressors measured in the compressor mode

- source combinatio n in the current reporting year and the preceding two reporting years (“Count m ” in Equation W

- 23). §98.236(o)(4)(ii) If the measurement methods specified in paragraphs §98.233(o)(3) or (o)(5) are conducted, report the measured volume of flow during the re porting year, in million standard cubic feet. §98.236(o)(5)(i) For centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production, the number of centrifugal compressors that have wet seal oil degassing vents. Reciprocating Compressors §98.236(p)(3)(i)(D) If the measurement methods specified in paragraphs §98.233(p)(2) or (p)(4) are conducted, then for each as found measurement performed on a leak or vent, the measured flow rate, in standard cubic feet per hour. §98.236(p)(3)(ii)(B) For each compressor mode

- source combination where a reporter emission factor as calculated in Equation W

- 28 was used to calculate emissions in Equation W

- 27, the compressor mode

- source combination reporter emission factor, in st andard cubic feet per hour (“EF s,m ” in Equation W

- 28). §98.236(p)(3)(ii)(C) For each compressor mode

- source combination where a reporter emission factor as calculated in Equation W

- 28 was used to calculate emissions in Equation W

- 27, the total number of compressors measured in the compressor mode

- source combination in the current reporting year and the preceding two reporting years (“Count m ” in Equation W

- 28). §98.236(p)(4)(ii) If the measurement methods specified in paragraphs §98.233(p)(3) or (p)(5) ar e conducted, the measured volume of flow during the reporting year, in million standard cubic feet. Equipment Leak Surveys §98.236(q)(3)(ix)(A) The total number of meter/regulator runs at above grade transmission

- distribution transfer stations at your facility (“Count MR ” in Equation W

- 32B of this subpart). §98.236(q)(3)(ix)(B) Average estimated time that each meter/regulator run at above grade transmission

distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in Equation W

- 32B of this subpart). Equipment Leaks by Population Counts §98.236(r)(1)(iii) Average estimated time that the emission source type was in operation in the calendar year, in hours (“T e ” in Equation W

- 32A of this subpart). §98.236(r)(2)(iii) Total number of meter/regulator runs at above grade metering

- regulating stations that are not above grade transmission

- distribution transfer stations (“Count MR ” in Equation W

- 32B of this subpart). §98.236(r)(2)(iv) Average estimated tim e that each meter/regulator run at above grade metering

regulating stations that are not above grade transmission

- distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in Equation W

- 32B of this subp art).

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- 5Table A

- 1. List of New and Revised Inputs to Emission Equations Affected by the Subpart W 2014 Amendments (continued)

Rule Citation Final Data Element EOR Injection Pumps §98.236(w)(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“V v ” in Equation W

- 37 of this subpart). §98.236(w)(7) Mass fraction of CO 2 in critical phase EOR injection gas (“GHG CO2 ” in Equation W

- 37 of this subpart). Onshore Natural Gas Processing §98.236(aa)(3)(v) For natural gas processing, the average mole fraction of CH 4 in natural gas received. §98.236(aa)(3)(vi) For natural gas processing, the average mole fraction of CO 2 in natural gas received.

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