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 Inputs to Emission Equations 

Affected by the Proposed “2015 Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems” 

In the proposed rulemaking titled “Revisions and Confidentiality Determinations for 

Petroleum and Natural Gas Systems” (referred to hereafter as the Subpart W 2015 Proposed 

Amendments), the EPA is proposing a number of changes to the subpart W reporting 

requirements, including that two new industry segments 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 Petroleum 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 facilities in the Onshore Petroleum and Natural Gas 

Production segment begin reporting emissions from completions and workovers of hydraulically 

fractured oil wells (currently subpart W only requires reporting of emissions from completions 

and workovers of gas wells). 

These proposed new reporting requirements would require the reporting of data elements 

that are inputs to emissions equations for new industry segments (the Onshore Petroleum and 

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

Pipeline segment) and for a new emission source in an existing segment (hydraulically fractured 

oil wells in the Onshore Petroleum and Natural Gas Production segment). As explained in the 

preamble to the proposed rule, we assigned these data elements to the Inputs to Emission 

Equations data category and evaluated potential disclosure concerns for these data elements. We 

followed the same steps set forth in a supporting memorandum1

 accompanying the rule deferring 

the reporting of inputs to emission equations.2 These steps are the following: 

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

• Step 2: For inputs that are not publicly available, evaluate whether release of the 

information is likely to result in substantial competitive harm. 

 

1

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

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

2

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

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

• Step 3: For inputs that are likely to cause substantial competitive harm if disclosed, 

evaluate potential alternative calculation methods.

• Step 4: For inputs that are likely to cause substantial competitive harm if disclosed, 

evaluate potential alternative verification methods. 

The purpose of this memorandum is to document this evaluation. The list of the 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 sources reviewed included the following: 

• Department of Energy, Energy Information Administration – www.eia.gov

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

• Department of Transportation, Pipeline and Hazardous Materials Safety 

Administration: Data and Statistics – www.phmsa.dot.gov

• American Petroleum Institute: Industry Statistics – www.api.org/statistics 

• American Gas Association – www.aga.org

• Railroad Commission of Texas – www.rrc.state.tx.us/data/index.php 

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

gas gathering and boosting segment. 

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

the same as the proposed inputs by considering the number of reporters represented by the data, 

the age of the data, and frequency of availability. Although we were able to locate some data that 

were similar to some of the proposed inputs, we were unable to locate any public sources of data 

that are exactly the same as the proposed new inputs, reported by the same reporters, and 

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

Step 2: Review for Potential Disclosure Concerns 

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

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

focused on the market structure of each industry segment because the structure of the market in 

which a reporter does business has a significant impact on the ability of a competitor to use the 

reported information to gain competitive advantage. Typically, economists use market 

concentration to assess market conditions and use tools such as the Herfindahl-Hirschman Index 
3 

to assess market concentration. However, Herfindahl-Hirschman Index values are not available 

for the petroleum and natural gas segments. As a result, the EPA conducted a qualitative analysis 

of the market structure for each of the affected industry segments and assessed potential concerns 

for each industry segment. The results of our analysis for each segment are summarized below. 

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

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

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

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

fractured oil wells. Onshore petroleum production is a regionally concentrated market, with wells 

located in fixed geological formations. Decisions on where to drill wells may be based on 

proprietary information during the early development of a formation when lease prices have not 

stabilized and operators are taking risks by drilling exploratory wells in formations that do not 

have proven production records. After several wells have been drilled in an area, information 

about production becomes publicly available and the advantage incurred by the operator drilling 

exploration wells is lost. However, once a well has been drilled, decisions to produce are based 

on market prices and the ability to control flow from the well. Although this could pose a 

potential data sensitivity with respect to exploration wells, for most exploratory wells this issue 

is addressed by the fact that onshore production data is reported at a sub-basin level, as defined 

by county boundaries, and which is a large enough scale that disclosure of the data collected 

under subpart W would not reveal any proprietary information about the facility or cost to do 

business. However, for two specific types of exploratory wells, delineation wells and wildcat 

wells, in specific cases discussed below, early public disclosure of 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 hydraulic fracturing, the cumulative gas 

flowback time, in hours, for each sub-basin, from when gas is first detected until 

sufficient quantities are present to enable separation (40 CFR 98.236(g)(5)(i)); 

• For oil well completions or workovers with hydraulic 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 hydraulic 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 annual gas-liquid separator oil volume 

that is sent to applicable onshore storage tanks, in barrels (40 CFR 98.236(j)(1)(v)). 
4 

The specific cases for which early public disclosure 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 hydraulic fracturing, where wildcat wells 

and/or delineation wells are the only wells in a sub-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 information on the productivity of the well. 

• For onshore production storage tanks, where wildcat wells and/or delineation wells 

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

wells in a sub-basin, then the volumes reported for these data elements would 

represent volumes of wildcat wells and/or exploratory wells exclusively, which could 

reveal information on the productivity of the well.

Delaying reporting of these data for two reporting years would be sufficient time for 

reporters to thoroughly conduct an assessment of the well, after which the data could be reported 

and made publicly available. Besides the need for a two-year delay for the 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 the EPA did not proceed 

to evaluate each “input to equation” data element in this segment. 

Onshore Natural Gas Transmission Pipeline Segment. Natural gas transmission 

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

other transmission compressors through transmission pipelines to natural gas distribution 

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

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

Existing pipeline construction and natural gas transmission technology and operations 

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

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

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

gas transmission pipeline segment compete with others in their region for shipments of natural 

gas. Even though there may be only one pipeline transmitting natural gas from one location to 

another, competition exists between firms that wish to accept shipments of natural gas within a 

given region, for transmission potentially to different endpoints. Such firms could make use of 

information about their competitors’ throughput quantity and/or cost structure to strategically set 

their prices or other contract terms. Even though the market is regulated by FERC, actual 

contract prices may be set at levels below the FERC-mandated maximum tariff. However, only 

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

a calendar year, if there was only one blowdown for a unique physical volume and equipment or 
5 

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

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

gain a competitive advantage. 

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

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

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

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

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

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

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

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

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

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

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

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

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

segment would not be likely to reveal any proprietary information about the facility or cost to do 

business. 

Step 3 and Step 4 

As noted above, disclosure of some of the inputs listed in Appendix A were determined 

to have early disclosure concerns in situations where the inputs are specific to exploratory wells. 

The EPA addressed this concern by providing an option in the 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 proceed to further evaluate the proposed 

“inputs to equations” data elements in subpart W under Steps 3 and 4. 
6 

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

Rule Citation Proposed Data Element 

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

Boosting) 

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

§98.233(a)(1) and (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 (“Tt” in Equation W-1 of 

this subpart). 

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

and Boosting) 

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

§98.236(c)(3) Average estimated number of hours in the calendar year the pumps 

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

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

§98.236(d)(1)(iii) Total feed rate entering the acid gas removal unit, using a meter or 

engineering estimate based on process knowledge or best available 

data, in million cubic feet per year. 

§98.236(d)(2)(i)(A) For each unit for which Calculation Methodology 1 or 2 in 

§98.233(d) is used, annual average volumetric fraction of CO2 in the 

vent gas exiting the acid gas removal unit. 

§98.236(d)(2)(i)(B) For each unit for which Calculation Methodology 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 Methodology 3 in §98.233(d) is 

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

flowing out of the acid gas removal unit, as specified in Equation W4A or Equation W-4B of this subpart. 

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

used, annual average volumetric fraction of CO2 content in natural 

gas flowing into the acid gas removal unit, as specified in Equation 

W-4A or Equation W-4B of this subpart. 
7 

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

Rule Citation Proposed Data Element 

§98.236(d)(2)(ii)(D) For each unit for which Calculation Methodology 3 in §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 volume of natural gas flow 

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

total annual volume of natural gas flow out of the acid gas removal 

unit, as specified in Equation W-4B of this subpart, in cubic feet at 

actual conditions,. 

§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 Fahrenheit. 

§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 Calculation Methodology 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 Methodology 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 Methodology 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 Methodology 4 in §98.233(d) is 

used, the solvent weight, in pounds per gallon. 

Dehydrators (Onshore Petroleum and Natural Gas Gathering and Boosting) 

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

per day, determined by engineering estimate based on best available 

data. 

§98.236(e)(1)(iv) Dehydrator feed natural gas water content, in pounds per million 

standard cubic feet. 

§98.236(e)(1)(v) Dehydrator outlet natural gas water content, in pounds per million 

standard cubic feet. 
8 

Appendix A: List of Inputs to Emission Equations Affected 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., triethylene glycol (TEG), diethylene glycol 

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

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

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

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

§98.236(e)(1)(xii) Temperature of the wet natural gas, 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 CH4 in wet natural gas. 

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

§98.236(e)(2)(i) The total number of glycol dehydrators 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 calculate annual volumetric total gas 

emissions for a single well, the cumulative gas flowback time, in 

hours, from when gas is first detected until sufficient quantities are 

present to enable separation (sum of “Tp,i” values used in Equation 

W-10A). 

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

emissions for a single well, the cumulative flowback time, in hours, 

after sufficient quantities of gas are present to enable separation (sum 

of “Tp,s” values used in Equation W-10A). 

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

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

hour, for each sub-basin (average of “FRs,p” values 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 (“GORp” 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 during the first 30 

days of production after completions of each newly drilled well or 

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

Equation W-12C). 
9 

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

Rule Citation Proposed Data Element 

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

emissions for completions that vent gas to the atmosphere, the vented 

natural gas volume, in standard cubic feet, for each well in the subbasin (“FVs,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 that vent gas to the atmosphere, the flow 

rate at the beginning of the period of time when sufficient quantities 

of gas are present to enable separation, in standard cubic feet per 

hour, for each well in the sub-basin (“FRp,i” in Equation W-10B). 

Blowdown Vent Stacks (Onshore Natural Gas Transmission Pipeline and Onshore 

Petroleum and Natural Gas Gathering and Boosting) 

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

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

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

blowdowns in the calendar year for the equipment or event type (the 

sum of equation variable “N” from Equation W-14A or Equation W14B of this subpart, for all unique physical volumes for the 

equipment or event type). 

Storage Tanks (Onshore Petroleum and Natural Gas Gathering 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 natural 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 or 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 CO2 mass, in metric tons CO2, that was 

recovered during the calendar year using a vapor recovery 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 CH4 mass, in metric tons CH4, that was 

recovered during the calendar year using a vapor recovery system. 
10 

Appendix A: List of Inputs to Emission Equations Affected 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 close properly during 

the calendar year, the total time the dump valves on gas-liquid 

separators did not close properly in the calendar year, in hours (sum 

of the “Tn” values in Equation W-16 of this subpart). 

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

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

Equations W-19 and W-20 of this subpart). 

§98.236(n)(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19 

of this subpart). 

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

combusted by a burning flare. 

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

W-19 of this subpart). 

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

W-20 of this subpart). 

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

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

vents. 

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

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

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

and Boosting) 

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

Equation W-32A of this subpart). 

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

in the calendar year, in hours (“Te” in Equation W-32A of this 

subpart). 
11 

Appendix A: List of Inputs to Emission Equations Affected 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), and geographic 

location combination in Tables W-1B and W-1C of this subpart, if the 

facility does contain the equipment type, the count of the major 

equipment type. 

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

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

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

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

than 1 million Btu per hour (or the equivalent of 130 horsepower); or 

internal fuel combustion units of any heat capacity that are 

compressor-drivers, report for each combustion unit type and fuel 

type combination, the quantity of fuel combusted in the calendar year, 

in thousand standard cubic feet, gallons, or tons.