E

C

/R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

 

MEMORANDUM

DATE: April 17, 2012

SUBJECT: Technology Review for the Final Amendments to Standards for the Oil and 

Natural Gas Production and Natural Gas Transmission and Storage Source 

Categories

FROM: Heather P. Brown, P.E.

TO: Greg Nizich, EPA/OAQPS/SPPD/FIG

Bruce Moore, EPA/OAQPS/SPPD/FIG

1.0 INTRODUCTION

Section 112 of the Clean Air Act (CAA) requires the EPA to establish technology-based 

standards for listed source categories. These technology-based standards are often referred to as 

MACT standards. The Oil and Natural Gas Production MACT (40 CFR 63, subpart HH) applies 

to major and area sources and regulates HAP emissions from certain affected sources at oil and 

natural gas production facilities. The Natural Gas Transmission and Storage MACT (40 CFR 63, 

subpart HHH) requirements apply to major sources and regulates HAP emissions from natural 

gas transmission and storage facilities. Extracted streams and recovered products, processes and 

operations, and HAP emission points are described in the following sections. Section 112 

contains provisions requiring the EPA to periodically revisit these standards. Specifically, 

paragraph 112(d)(6) states:

(6) REVIEW AND REVISION. – The Administrator shall review, and revise as 

necessary (taking into account developments in practices, processes, and control 

technologies), emission standards promulgated under this section no less often than every 

8 years.

To comply with this CAA requirement, the EPA conducted a technology review for each of these

MACT standards for major sources (area sources were not included in this technology review; it 

has been less than 8 years since the area source rule was promulgated.

For the purpose of reviewing the MACT standards, the EPA considers a “development” in 

practices, processes, and control technologies to be: 

 Any add-on control technology or other equipment that was not identified and considered 

during MACT development,
2

 Any improvements in add-on control technology or other equipment (that was identified 

and considered during MACT development) that could result in significant additional 

emission reduction,

 Any work practice or operational procedure that was not identified and considered during 

MACT development, and 

 Any process change or pollution prevention alternative that could be broadly applied that 

was not identified and considered during MACT development.

Section 2 presents a summary the sources of data used to conduct the technology review. 

Section 3 presents a background for the source categories included in this technology review. 

Section 4 presents a summary of the technology review for glycol dehydration units. A summary 

of the technology review for storage vessels with the potential for flash emissions is presented in 

Section 5 and Section 6 presents a summary of the technology review for equipment leaks. 

2.0 SOURCES OF AVAILABLE CONTROL TECHNOLOGY INFORMATION

To identify control technologies for glycol dehydration units and storage vessels with the 

potential for flash emissions, we consulted the following sources of data: RACT/BACT/LAER 

Clearinghouse, Natural Gas STAR Program, and State regulations. For equipment leaks from 

natural gas processing plants, we consulted State/local regulations and the background 

information from the development of the proposed Uniform Standards.

2.1 RACT/BACT/LAER Clearinghouse Database

Under the EPA's New Source Review (NSR) program, if a company is planning to build a new 

plant or modify an existing plant such that criteria air pollution emissions will increase by a 

certain amount, then the company must obtain an NSR permit. The NSR permit is a construction 

permit which generally requires the company to minimize air pollution emissions by changing 

the process to prevent air pollution and/or installing air pollution control equipment. 

The terms "RACT," "BACT," and "LAER" are acronyms for different program requirements 

relevant to the NSR program. RACT, or Reasonably Available Control Technology, is required 

on sources in areas that are not meeting national ambient air quality standards (non-attainment 

areas). BACT, or Best Available Control Technology, is required on new or modified major 

sources in clean areas (attainment areas). LAER, or Lowest Achievable Emission Rate, is 

required on new or modified major sources in non-attainment areas. 

BACT and LAER (and sometimes RACT) are determined on a case-by-case basis, usually by 

State or local permitting agencies. The EPA established the RACT/BACT/LAER Clearinghouse, 

or RBLC, to provide a central data base of air pollution technology information (including past 

BACT and LAER decisions contained in NSR permits) to promote the sharing of information 

among permitting agencies and to aid in future case-by-case determinations. However, data in 

the RBLC are not limited to sources subject to RACT, BACT, and LAER requirements. 
3

Noteworthy prevention and control technology decisions and information may be included even 

if they are not related to past RACT, BACT, or LAER decisions.1

The RBLC contains over 5,000 air pollution control permit determinations that can help identify 

appropriate technologies to mitigate most air pollutant emission streams. It was designed to help 

permit applicants and reviewers make pollution prevention and control technology decisions for 

stationary air pollution sources, and includes data submitted by several U.S. territories and all 50 

States on over 200 different air pollutants and 1,000 industrial processes.

The RBLC provides several options for searching the permit database on-line to locate 

applicable control technologies. On April 3, 2012, we conducted a search of the RBLC. Our 

search specified VOC- and HAP-emitting processes from North American Industry 

Classification System (NAICS) codes 21111*, 221210, and 4862102 with permits dating back to 

1997. The search results included the following data fields:

 RBLC ID;

 Facility Name, and State;

 Standard Industrial Classification (SIC), and NAICS;

 Facility description;

 Process name and process notes;

 Throughput;

 Pollutant;

 Control technology and emission limit; and

 Percent efficiency of control.

The results of the search are presented in Attachment 1 for glycol dehydration units and storage 

vessels with the potential for flash emissions.

2.2 Natural Gas STAR Program

New practices, processes, and control technologies were reviewed from the Natural Gas STAR 

program. The Natural Gas STAR Program is a flexible, voluntary partnership that encourages 

oil and natural gas companies to adopt cost-effective technologies and practices that improve 

operational efficiency and reduce pollutant emissions. The program provides the oil and gas 

industry with information on new techniques and developments to reduce pollutant emissions 

from the various processes. The “Lessons Learned” documents and “Partner Reported 

Opportunities” fact sheets provide a comprehensive evaluation of available control technologies 

for the oil and natural gas production and transmission and storage source categories. The results 

of the search of the Natural Gas STAR program are presented within the discussion for each 

emission point.

 

1 Technology Transfer Network: Clean Air Technology Center. RACT/BACT/LAER Clearinghouse Basic 

Information. http://www.epa.gov/ttn/catc/rblc/htm/welcome_eg.html.

22 Dehy was used instead of dehydrator to ensure that process names with both dehydration units and dehydrators 

would be extracted from the database.2 These NAICS codes were chosen to be most inclusive of facilities in the oil 

and natural gas production and natural gas transmission source categories.
4

2.3 State Regulations

We also conducted a search of available State regulations with respect to the affected facilities 

subject to subpart HH and HHH. This includes a search of the State regulations suggested by the 

commenters3as being more stringent (specifically California, Colorado, and Wyoming). We only 

report State regulations that were found to be more stringent than the MACT standards.

3.0 BACKGROUND FOR OIL AND NATURAL GAS PRODUCTION AND 

NATURAL GAS TRANSMISSION AND STORAGE SOURCE CATEGORIES

On August 23, 2011, the U.S. Environmental Protection Agency (EPA) proposed amendments to 

subpart HH for existing and new major sources in the oil and natural gas production source 

category and subpart HHH for the natural gas transmission and storage source category. The 

public comment period closed on November 30, 2011, and the EPA received several comments 

regarding the technology review conducted for sources subject to subpart HH and HHH. 

Subpart HH applies to the oil and natural gas production source category and includes the 

separation, upgrading, storage, and transfer of extracted streams (primarily hydrocarbons) that 

are recovered from production wells. The extracted streams and recovered products for this 

source category include crude oil, condensate, natural gas, and produced water. The oil and 

natural gas production source category includes the processing and upgrading of crude oil prior 

to the point of custody transfer, and natural gas prior to entering the pipeline systems associated 

with the natural gas transmission and storage source category. This source category also 

includes offshore production platforms located in State waters. The types of processes and 

operations in this source category include production wells, dehydration units, tank batteries, 

natural gas processing plants, and offshore production platforms. The affected facilities 

regulated by the subpart HH MACT standards are glycol dehydration units, storage vessels with 

the potential for flash emissions, and ancillary equipment4and compressors (i.e., equipment 

leaks) at natural gas processing plants (NGPP).

The natural gas transmission and storage source category includes the pipeline transport, storage, 

and processing of natural gas prior to entering the final pipeline of the local distribution company 

that delivers natural gas to the final end user. The affected facility regulated by the subpart HHH 

MACT standards is glycol dehydration units.

4.0 TECHNOLOGY REVIEW FOR GLYCOL DEHYDRATION UNITS

Glycol dehydration units are used as stand-alone units that remove water and other condensates 

in natural gas from an individual well or several wells. In addition, dehydration units may be 

part of various processing units at condensate tank batteries, natural gas processing plants, and 

offshore production platforms. Dehydration is necessary to remove water vapor which may form 

hydrates that can cause corrosion and plug equipment lines. Triethylene glycol (TEG) 

dehydration units account for most of the population of dehydration units, with ethylene glycol 

 

3 Comment received from Devorah Ancel, Sierra Club et al. EPA Docket No. EPA-HQ-OAR-2010-0505-4457.

4 Ancillary equipment is defined in §63.761 as any of the following pieces of equipment: pumps, pressure relief 

devices, sampling connection systems, open-ended valves, or lines, valves, flanges, or other connectors.
5

(EG), diethylene glycol (DEG), and solid desiccant dehydration units accounting for the 

remaining portion. 

This section presents the technology review conducted for glycol dehydration units in both the 

production and transmission and storage source categories. Section 4.1 presents a summary of 

level of control of the current MACT standards and the technologies evaluated during the 

development of those standards. Section 4.2 presents an analysis for identified control 

technologies to determine whether they qualify as “developments in practices, processes, and 

control technologies” for these source categories under section 112(d)(6).

4.1 Summary of Existing MACT Level of Control

The glycol dehydration unit MACT standards promulgated in 1999 for the oil and natural gas 

production (subpart HH) and the natural gas transmission and storage (subpart HHH) source 

categories are similar and will be discussed in this section together. For the 1999 glycol 

dehydrator MACT standards for both subpart HH and subpart HHH, the MACT floor was 

determined to be 95 percent control. The subpart HH requirements are applicable to glycol 

dehydration units that process an actual annual average flow rate of greater than or equal to 3 

million standard cubic feet per day (MMscf/d) and emit benzene emissions greater than or equal 

to 1 ton per year (tpy). The subpart HHH requirements are applicable to dehydration units that 

process an actual annual average flow rate of greater than or equal to 10 MMscf/d and emit 

greater than or equal to 1 tpy of benzene.

During the development of the 1999 MACT standards, a variety of control technologies were 

considered, including condensation, combustion, and a combination of condensation and 

combustion. The types of control technologies used by the industry were reported, in other 

applications, to achieve varying levels of emission reduction (e.g., ranging from 95 to 98 percent 

or greater).

5,6

 At the time, EPA was unable to document the emission reduction efficiencies 

being achieved by the controls reported to be in place for glycol dehydrators in these source 

categories but determined based in part on modeling using GRI-GLYCalcTM (Version 3.0) that 

95 percent reduction was appropriate as MACT. Attachments 2 and 3 present a summary of the 

data collected during the MACT development for 63 large glycol dehydration units in the 

production source category and 64 large glycol dehydration units in the natural gas transmission 

and storage source category. These datasets represent our best available data on glycol 

dehydration units that contain size and process characteristics (e.g., BTEX loading, inlet stream 

temperature and pressure, natural gas throughput). However, to estimate impacts, we used the 

2005 NEI dataset (Attachments 4 and 5), which we believe contains the most current emissions 

data. However, because process characteristics are not included in the NEI dataset, the original 

MACT dataset was used to characterize the source category.

4.2 Identified Control Technologies for Glycol Dehydration Units

 

5 Memorandum from Viconovic, G., and Fitzsimons, G., EC/R Incorporated, to Smith, M., US EPA. 

Recommendation of MACT Floor Levels for HAP Emission Points at Major Sources in the Oil and Natural Gas 

Production Source Category. September 23, 1997. Legacy Docket A-94-04 No. II-A-07.

6 Memorandum from Viconovic, G., and Fitzsimons, G., EC/R Incorporated, to Smith, M., US EPA. 

Recommendation of MACT Floor Levels for HAP Emission Points at Major Sources in the Natural Gas 

Transmission and Storage Source Category. September 23, 1997. Legacy Docket A-94-04 No. II-A-06.
6

The following practices, processes, and control technologies were considered during MACT 

development for glycol dehydration units subject to subpart HH and HHH: add-on controls 

(condensers; combustion devices, including catalytic incinerators and thermal incinerators; and 

carbon bed adsorbers) and pollution prevention. For each of the add-on control devices, a 95 

percent emission reduction was determined to be the level of control. Process modifications 

were also presented as a viable option for control.7In addition, glycol dehydration unit process 

vents8that are connected to a process natural gas line are considered to be in compliance with the 

MACT standards. Table 1 presents the findings of a search of the RBLC database and Table 2 

presents the results of a search of the Natural Gas STAR website for glycol dehydration unit 

control devices. In addition to the RBLC database and the Natural Gas STAR program, we 

consulted State regulations to identify any requirements more stringent than the MACT standard. 

Table 3 presents the results of this search only for State requirements more stringent than 

MACT. 

Since the MACT standard for large glycol dehydration units is 95 percent emission reduction, we 

focused the technology review on developments that would achieve greater than 95 percent 

emission reduction. In addition, the EPA can consider cost in its section 112(d)(6) review. The 

next sections address how EPA considered potential developments in practices, processes, and 

control technologies for the subpart HH and HHH MACT standards for glycol dehydration units. 

4.2.1 Add-on Control Technology or Other Equipment Not Identified and Considered During 

MACT Development

As previously stated, the technologies considered during MACT development of the 95 percent 

emission reduction requirement for both subparts included add-on controls (condensers, 

combustion devices, and carbon bed adsorbers). Table 1 presents a summary of the search of the 

RBLC database. All of the add-on controls presented in Table 1 were identified and considered 

during the MACT development.

The search of the Natural Gas STAR program identified the following types of control 

technologies not identified and considered during MACT development: replacement of glycol 

dehydration unit with methanol injection; zero emissions dehydrators; and replacement of glycol 

dehydrators with desiccant dehydrators. The following evaluates the feasibility of using these 

types of control technology for setting a standard for large glycol dehydration units.

Methanol Injection

As shown in Table 2, this technology has been used for low pressure systems (50 to 400 psi), but 

there is no information on the effectiveness of this technology for high pressure systems. Based 

on the datasets in Attachments 2 and 3 described above, all of the glycol dehydration units in the 

 

7 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, 

NC. National Emission Standards for Hazardous Air Pollutants for Source Categories: Oil and Natural Gas 

Production and Natural Gas Transmission and Storage. Background Information Document for Proposed Standards. 

EPA-453/R-94-079a.

8 Glycol dehydration unit process vent is defined in §63.761 as the glycol dehydration unit reboiler vent and the vent 

from the gas-condensate-glycol (GCG) separator (flash tank), if present.
7

Table 1. Control Technologies Identified for Glycol Dehydration Units in the April 3, 2012, Query of the RBLC Database

RBLC ID Facility Name State Process_Name Throughput

Throughput

Unit Control Technology

Emission 

Reduction

(%)

MI-0305 Consumers Energy 

(Muskegon River 

Compressor)

MI Glycol Dehydrator, 

Triethylene

260 MMscf/day Thermal Oxidizer. 

Designed For 1400oF and 

0.5 Second Residence.

98

MI-0325 Michigan 

Consolidated Gas 

(Belle River Mills)

MI Glycol Dehydrator 986 MMscf/day Enclosed Flare Control of 

Still Off Gas.

99

MI-0325 Michigan 

Consolidated Gas 

(Belle River Mills)

MI Glycol Dehydrator 986 MMscf/day Enclosed Flare Control of 

Still Off-Gas

99

OK-0026 Swift Energy OK Dehydration Unit 20 MMscf/day Flare 99

NOTE: Only entries with emission reductions equal to or greater than 95 percent are presented.
Table 2. Natural Gas STAR Program Glycol Dehydration Unit Control Technologies

Control 

Technology Description Applicability

Type of 

Control 

Technology

Associated

Gas Savings 

(Mcf)9 Comments Ref

Reroute 

Glycol 

Skimmer Gas

Reroute the condensate separator gas, called 

skimmer gas, to the reboiler firebox or other 

low pressure fuel gas systems for fuel use 

can reduce VOC and HAP emissions

Applicable to reboilers with fuel 

gas consumption levels that can 

accommodate the volume of rerouted skimmer gas

Process 

modification

790 (for 20 

MMscf/day 

unit)

No information was 

provided on the level of 

VOC and HAP emission 

reductions.

10

Pipe Glycol 

Dehydrator to 

Vapor 

Recovery 

Unit (VRU)

Flash tank separators and other vents are 

piped to a VRU. The VRU boosts the 

recovered gas pressure enough to inject it 

into a fuel gas system, compressor suction, 

or gathering/sales line.

VRU must have sufficient spare 

capacity 

Process 

modification

790 (for 20 

MMscf/day 

unit)

No information was 

provided on the level of 

VOC and HAP emission 

reductions.

11

Replace 

Glycol 

Dehydration 

Units with 

Methanol 

Injection

Replace glycol dehydrator with methanol 

injection as a method of controlling gas 

hydrate formation in gas lines than glycol 

dehydration. Methanol injection prevents 

hydrate formation in the natural gas and 

eliminates HAP emissions from the glycol 

dehydrator. Requires a methanol pump 

requiring either electricity or solar power.

This technology has been used 

for low pressure systems (50 to 

400 psi), but there is no 

information on the effectiveness 

of this technology for high 

pressure systems. In addition, 

field personnel are required.

Equipment 800 Many glycol 

dehydration units 

subject to subparts HH 

and HHH are remote 

without electricity.

12

Zero 

Emissions 

Dehydrators

Combine several technologies to virtually 

eliminate HAP emissions. Equipment 

includes flash tanks, electric pumps, and 

electric control valves. Collect all 

condensable components from the still 

column vapor and use the remaining noncondensable still vapor as fuel for the glycol 

reboiler.

Requires electric utilities or an 

engine-generator set to achieve 

zero emissions.

Equipment 26,900 

(average)

Cost data provided do 

not include the 

additional costs required 

for an engine-generator 

set

13

 

9 Gas savings reported for technologies, but no information is available in the Natural Gas STAR documents to indicate what percent reduction this represents.

10 EPA (2004). Partner Reported Opportunities: Reroute Glycol Skimmer Gas. Natural Gas STAR.

11 EPA (2011). Partner Reported Opportunities: Pipe Glycol Dehydrator to Vapor Recovery Unit. Natural Gas STAR.

12 EPA (2004). Partner Reported Opportunities: Replace Glycol Dehydrators with Methanol Injection. Natural Gas STAR.

13 EPA (2011). Partner Reported Opportunities: Zero Emissions Dehydrators. Natural Gas STAR. 
Table 2. Natural Gas STAR Program Glycol Dehydration Unit Control Technologies (continued)

9

Control 

Technology Description Applicability

Type of 

Control 

Technology

Associated

Gas Savings 

(Mcf)9 Comments Ref

Optimize 

Glycol 

Circulation 

and Install 

Flash Tank 

Separators in 

Glycol 

Dehydrators

By optimizing the glycol circulation rate, 

the facility can prevent the over-circulation 

of the glycol solution in the dehydrator, thus 

reducing the potential emissions of HAP. 

Over circulation of the glycol solution does 

not significantly reduce the moisture 

content in the natural gas; however it may 

increase HAP emissions.

Applies to glycol dehydration 

units for which glycol is overcirculated and no flash tank 

exists

Process 

Modification

Range from 

370 to 

37,000

No information was 

provided on the level of 

VOC and HAP emission 

reductions

14

Replacing 

Gas-Assisted 

Glycol Pumps 

with Electric 

Pumps

Gas-assisted pumps are used in remote 

areas that do not have an electrical power 

supply and are designed to take advantage 

of the energy of high-pressure natural gas 

entrained in the rich (wet) glycol solution 

leaving the gas contactor. The seals in 

these pumps wear over time and result in 

contamination of the lean (dry) glycol 

solution making it less efficient in 

dehydrating the gas, which increases the 

glycol circulation rates, and increases HAP 

emissions.

If the glycol dehydration unit has 

a flash tank separator, and a 

beneficial use for all gas 

recovered, then gas savings 

might not provide enough cost 

justification for installing an 

electric pump.

Electricity is required for 

operation.

Process 

Modification

360 to 

36,000

Many glycol 

dehydration units 

subject to subparts HH 

and HHH are remote 

without electricity.

No information was 

provided on the level of 

VOC and HAP emission 

reductions

15

Replacing 

Glycol 

Dehydrators 

with 

Desiccant 

Dehydrators

Replacing glycol dehydrators with desiccant 

dehydrators reduces HAP emissions by 

99 percent by passing the wet gas through a 

drying bed of desiccant tablets. The tablets 

pull moisture from the gas and gradually 

dissolve in the process. This technology is 

feasible for low temperature, high pressure 

processing facilities, but has not been 

proven for gas volumes greater than 5 

million cubic feet per day (5 MMscfd).

Usually used by partners when 

the volume to be dried is 5 

MMscf/day or less and when 

wellhead gas temperature is low 

(< 70oF) and the pressure is high 

(>100 psig). Cooling or 

compressing the gas in order to 

use a desiccant dehydration unit 

increases system complexity and 

typically is cost prohibitive.

Equipment 444 Potentially reduces HAP 

emissions by 99 percent.

16

 

14 EPA (2006). Lessons Learned: Optimize Glycol Circulation and Install Flash Tank Separators in Glycol Dehydrators. Natural Gas STAR.

15 EPA (2006). Lessons Learned: Replacing Gas-Assisted Glycol Pumps with Electric Pumps. Natural Gas STAR.

16EPA (2006). Lessons Learned: Replacing Glycol Dehydrators with Desiccant Dehydrators. Natural Gas STAR.
10

Table 3. State Regulations for Glycol Dehydrators - Greater Than 95 Percent Control 

Requirements

State Source Applicability Standard Compliance Options

WY Varies based on location within the State 98% -Approved control device 

(enclosed combustion or other)

- Modify or install glycol 

circulation pump to limit 

circulation rate

Controls may be removed after 

one year if total potential VOC 

emissions are less than 6 tpy 

and units are equipped with still 

vent condensers.
11

oil and natural gas production data set have pressures greater than 400 psig and over half of the 

glycol dehydration units in the natural gas transmission and storage dataset have pressures 

greater than 400 psig. As a result, we conclude that methanol injection is not technically 

feasible, and therefore not a development in practices, processes, and control technologies, for 

the large glycol dehydration unit subcategory.

Zero Emissions Dehydrators

Zero emissions dehydrators combine several technologies to virtually eliminate HAP 

emissions.17 This includes installation of flash tanks, electric pumps and control valves, and 

reboiler still vent condensers. According to the Natural Gas STAR Partner Reported 

Opportunities fact sheet (PRO Fact Sheet No. 206),18 this technology can be applied to various 

onshore production, processing, and gas transportation settings. As such, we evaluated the cost 

effectiveness of this control technology to determine whether it is economically feasible. 

To determine whether the zero emissions dehydrator technology would be economically feasible, 

we calculated the incremental costs between installing this type of technology and installing a 

condenser and flash tank (which were assumed to have been installed to comply with MACT).19

Total capital investment (TCI) for a condenser and flash tank was calculated based on the 

condenser costs calculated for the 1999 MACT,20 scaled to 2008 dollars using the Chemical 

Engineering21 cost index for equipment costs.

To develop the TCI for the zero emissions dehydrator, the cost information in the PRO Fact 

Sheet No. 20622 was used. It was reported in the PRO Fact Sheet No. 206 that the cost data 

represented equipment sized for a 28 MMscf/day glycol dehydrator. These estimates were based 

on 2011 cost data. Therefore, the cost data were revised to reflect 2008 dollars using the 

Chemical Engineering23 cost index for equipment costs. According to the information on large 

glycol dehydration units in the MACT dataset for production, the average glycol dehydrator 

natural gas throughput is 17 MMscf/day (see Attachment 2). Therefore, costs presented in the 

PRO Fact Sheet No. 206 were adjusted to represent a 17 MMscf/day dehydration unit. The 

procedures laid out in the OAQPS Control Cost Manual (OCCM)24 were used for estimating 

TCI. 

 

17 See Reference 13.

18 See Reference 13.

19 The pieces of equipment included in the zero emissions dehydrator cost estimate include a flash tanks, electric 

pumps and control valves, and reboiler still vent condensers. It was assumed that the costs presented for the zero 

emissions dehydrator represented a purchased equipment package and integrated design. As such it was assumed 

that the existing condenser and flash tank would have to be removed. Therefore incremental costs represent the 

difference between the sunk cost of the condenser plus flash tank and the zero emissions dehydrator.

20 See Reference 7.

21 Chemical Engineering. http://www.che.com. August 2004. Economic Indicators. 

22 See Reference 13. It was assumed that the costs presented in the Fact Sheet represented purchased equipment 

costs and not TCI.

23 See Reference 21.

24 OAQPS Control Cost Manual: Fourth Edition (EPA 450/3-90-006, January 1990). U.S. Environmental Protection 

Agency. Research Triangle Park, NC.
12

Tables 4 and 5 present the TCI for installing a condenser and flash tank and a zero emissions 

dehydrator, respectively, in the production source category. The TCI for a condenser was 

estimated to be $19,860 and for a zero emissions dehydrator, the TCI was estimated to be 

$58,090.

Table 6 presents the total annual costs (TAC) for both condensers and zero emissions 

dehydration units for the production source category. The procedures used for estimating TAC 

from condensers was based on the OCCM.25 For zero emission dehydration units, a similar 

methodology was used. It was assumed that the operating labor requirements for both 

condensers and zero emissions dehydrators would be the same.26 It was also assumed that the 

operating and maintenance (O&M) costs presented in PRO Fact Sheet No. 206 for the electric 

pump were only attributable to electricity requirements. As shown in Table 6, TAC for a 

condenser was calculated to be $19,126/yr and for a zero emissions dehydration unit, TAC was 

$26,874. The incremental annual cost of installing the zero emissions dehydration unit was 

estimated to be $7,747/yr.

The same cost approach was used for the transmission and storage source category and TCI for 

the transmission and storage source category is presented in Tables 7 and 8. The average natural 

gas throughput for a large glycol dehydration unit in the transmission and storage MACT dataset 

is 107 MMscf/day (see Attachment 3) and capital costs were scaled accordingly. The TCI for a 

condenser was estimated to be $19,860 and for a zero emissions dehydrator, the TCI was 

estimated to be $365,830. Table 9 presents the TAC calculation for the transmission and storage 

source category. As shown in Table 9, TAC for a condenser was calculated to be $19,126/yr and 

for a zero emissions dehydration unit, TAC was $72,973/yr, with an incremental annual cost of 

$53,847/yr.

Cost effectiveness for each control technology and the incremental cost effectiveness evaluation 

is presented in Attachments 3 and 4, for production and transmission and storage source 

categories, respectively, and is summarized in Table 10. Average uncontrolled emissions were 

calculated for each glycol dehydration unit identified in the 2005 NEI dataset, assuming that all 

glycol dehydration units that are reported to be controlled are currently subject to and meeting 

the 95-percent MACT level of control.27 We assumed that while the control technology is 

referred to as zero emissions dehydration units, 100 percent emission reduction is not achieved 

using this control technology. Therefore, a 99.9 percent emission reduction was used to 

determine emission reductions. Attachments 3 and 4 present the incremental cost analysis for 

each existing glycol dehydration unit in the 2005 NEI dataset. As shown in Table 10, the 

average incremental cost effectiveness for the production source category is $18,066/ton. For 

 

25 See Reference 24.

26 “Employer Costs for Employee Compensation Historical Listing. March 2004 – September 2010. Bureau of 

Labor Statistics. Washington, DC. (ftp://ftp.bls.gov/pub/special.requests/ocwc/ect/ececqrtn.pdf) Table 9 – Private 

industry workers, by major occupational group: employer costs per hours worked for employee compensation and 

costs as a percentage of total compensation; 2004 – 2010. Management hours (Management, professional, and 

related occupations); Technical labor rates (Natural resources, construction, and maintenance occupations).

27 The NEI dataset does not contain the information necessary to identify which glycol dehydration units are subject 

to the MACT and their actual control performance.
13

Table 4. Total Capital Investment for Large Glycol Dehydration Units that Install a 

Condenser plus Flash Tank – Production Source Category

Equipment Description Size Factor Reference

Jul-93 

Cost

2008

Costa

Condenser Condenser, 

piping to 

control device

All 28 $6,800b$9,921

Condensate 

storage 

vessel

Fixed-roof 

tank

50 gal 2.72 (Vtank) + 1,960 29 $2,210 $3,224

Flash tank Low pressure 

separator

125 psig 30 $1,750 $2,553

Purchased equipment cost (PEC)c$10,760 $15,698

Enhanced monitoring equipment (EM) 0.10(PEC) $1,076 $1,570

Total capital investment for an existing 

unit (TCIE)d

1.15(PEC + EM) $13,620 $19,860

Minor discrepancies may be due to rounding.

a Costs escalated from July 1993 dollars to 2008 dollars using the ratio of Chemical Engineering cost indices 

(Reference 31). July 1993 Cost Index = 394.4; 2008 Cost Index = 575.4.

bDirect and indirect costs are included in the condenser cost. 

c

Procedures followed from OAQPS Control Cost Manual for calculating PEC and TCI (Reference 32).

dTotal capital investment for an existing unit accounts for a retrofit factor of 1.15.

 

28 See Reference 7.

29 See Reference 7.

30 See Reference 7. 

31 See Reference 23. 

32 See Reference 24. 
14

Table 5. Total Capital Investment for Zero Emissions Dehydration Unit – Production 

Source Category

Equipment Description Size Factor Oct 2011 Cost 2008 Costa,b

Condenserc Condenser (assume

includes piping to control 

device)

28 

MMscf/d

$14,000 -

$25,000

$11,821 $11,451 

Electric Pumpc28 

MMscf/d

$1,400-$25,000 $8,002 $7,752 

Flash tankc Low pressure separator 28 

MMscf/d

$6,500 - 18,800 $7,669 $7,429 

 Total equipment cost (EC) $26,631 

Purchased equipment cost (PEC)

Instrumentation 0.01 EC $266 

Sales Tax 0.03 EC $799 

Freight 0.05 EC $1,332 

PEC = $29,028 

Direct installation costsd

Foundation and 

support

0.08 PEC $2,322 

Handling and 

erection

0.14 PEC $4,064 

Electrical 0.08 PEC $2,322 

Piping 0.02 PEC $581 

Insulation 0.1 PEC $2,903 

Paint 0.01 PEC $290 

Total Direct Costs (DC) $41,510

Indirect Costs 

(installation)

Engineering 0.1 PEC $2,903 

Construction and 

field expenses

0.05 PEC $1,451 

Contractor fees 0.1 PEC $2,903 

Startup 0.02 PEC $581 

Performance test 0.01 PEC $290 

Contingencies 0.03 PEC $871 

Total Indirect Costs (IC) $8,999

Total capital investment for an existing unit (TCIE)e

1.15(PEC + DC + IC ) $58,090 

aCosts scaled from October 2011 dollars to 2008 dollars using the ratio of Chemical Engineering cost indices 

(Reference 33). October 2011 Cost Index = 594; 2008 Cost Index = 575.4.

bCosts scaled to system sized for an average throughput of 17 MMscf/day in the MACT dataset (see Attachment 2).

cCapital Cost provided by Natural Gas STAR PRO FS 206 (Reference 34) Capital cost assumed to be PEC.

d

Site prep and building not included in this assessment, assumed that site prep was already performed and building 

already exists.

eTotal capital investment for an existing unit accounts for a retrofit factor of 1.15.

 

33 See Reference 23.

34 See Reference 13.
15

Table 6. Total Annual Cost for Condensers and Zero Emissions Dehydration Unit –

Production Source Category

Condenser

Zero Emiss 

Dehy

Direct Annual Costs (DAC)a

Operating labor 130 hours/yr x $technical labor rateb$3,960 $3,960 

Supervising labor 0.15 x Operating labor x management labor ratec937 937 

Operating materials None required 0 0 

Maintenance

 Labor 130 hours/yr x $technical labor rateb3,960 3,960 

 Material 0.50 x Maintenance laborc1,980 1,980 

Utilities Annual O&M associated with pumps assumed to be electrical 

costs (Range from $165 to $6,500 per yr for 28 MMscf/day

adjusted for avg dehy size) Nat. Gas STAR PRO FS 206

2,020 

DAC = $10,837 $12,857 

Indirect Annual Costs (IAC)a

Overhead 0.60 x Total labor plus Maintenance materials $5,314 $5,314 

Administrative 0.02 x TCIEd397 1,162

Property tax 0.01 x TCIEd199 581

Insurance 0.01 x TCIEd199 581

Capital recoverye 0.1098 x TCIEd2,181 6,378

IAC = $8,289 $14,016

Total Net Annual Cost (DAC + IAC) $19,126 $26,874

a

Procedures followed from OAQPS Control Cost Manual for calculating PEC and TCI (Reference 35).

bTechnical Labor Rate = $30.46/hr (Reference 36).

cManagement Labor Rate = $48.04/hr (Reference 37).

dTCIE from Table 4 for condenser and Table 5 for zero emissions dehydrator.

eCapital recovery is based on equipment life of 15 years and an interest rate of 7%.

 

35 See Reference 24.

36 See Reference 26.

37 See Reference 26. 
16

Table 7. Total Capital Investment for Large Glycol Dehydration Units that Install a 

Condenser plus Flash Tank – Transmission and Storage Source Category

Equipment Description Size Factor Reference

Jul-93 

Cost

2008

Costa

Condenser Condenser, 

piping to 

control device

All 38 $6,800b$9,921

Condensate 

storage 

vessel

Fixed-roof 

tank

50 gal 2.72 (Vtank) + 1,960 39 $2,210 $3,224

Flash tank Low pressure 

separator

125 psig 40 $1,750 $2,553

Purchased equipment cost (PEC)c$10,760 $15,698

Enhanced monitoring equipment (EM) 0.10(PEC) $1,076 $1,570

Total capital investment for an existing 

unit (TCIE)d

1.15(PEC + EM) $13,620 $19,860

Minor discrepancies may be due to rounding.

a

Costs escalated from July 1993 dollars to 2008 dollars using the ratio of Chemical Engineering cost indices 

(Reference 41). July 1993 Cost Index = 394.4; 2008 Cost Index = 575.4.

bDirect and indirect costs are included in the condenser cost.

c

Procedures followed from OAQPS Control Cost Manual for calculating PEC and TCI (Reference 42).

dTotal capital investment for an existing unit accounts for a retrofit factor of 1.15.

 

38 See Reference 7. 

39 See Reference 24.

40 See Reference 7. 

41 See Reference 23.

42 See Reference 24. 
17

Table 8. Total Capital Investment for Zero Emissions Dehydration Unit – Transmission 

and Storage Source Category

Equipment Description Size Factor Oct 2011 Cost 2008 Costa,b

Condenserc Condenser (assume

includes piping to control 

device)

28 

MMscf/d

$14,000 -

$25,000

$74,453 $72,121

Electric Pumpc28 

MMscf/d

$1,400-$25,000 $50,399 $48,821

Flash tankc Low pressure separator 28 

MMscf/d

$6,500 - 18,800 $48,299 $46,786

 Total equipment cost (EC) $26,631 

Purchased equipment cost (PEC)

Instrumentation 0.01 EC $1,677 

Sales Tax 0.03 EC $5,032 

Freight 0.05 EC $8,386 

PEC = $182,824 

Direct installation costsd

Foundation and 

support

0.08 PEC $14,626 

Handling and 

erection

0.14 PEC $25,595 

Electrical 0.08 PEC $14,626 

Piping 0.02 PEC $3,656 

Insulation 0.1 PEC $18,282 

Paint 0.01 PEC $1,828 

Total Direct Costs (DC) $261,438 

Indirect Costs 

(installation)

Engineering 0.1 PEC $18,282 

Construction and 

field expenses

0.05 PEC $9,141 

Contractor fees 0.1 PEC $18,282 

Startup 0.02 PEC $3,656 

Performance test 0.01 PEC $1,828 

Contingencies 0.03 PEC $5,485 

Total Indirect Costs (IC) $56,675 

Total capital investment for an existing unit (TCIE)e

1.15(PEC + DC + IC ) $318,113 

aCosts scaled from October 2011 dollars to 2008 dollars using the ratio of Chemical Engineering cost indices 

(Reference 43). October 2011 Cost Index = 594; 2008 Cost Index = 575.4.

b Costs scaled to system sized for an average throughput of 107 MMscf/day in the MACT dataset (see 

Attachment 3).

cCapital Cost provided by Natural Gas STAR PRO FS 206 (Reference 44) Capital cost assumed to be PEC.

Assumed that the midpoint of the range represents the 28 MMscf/day dehydration unit.

d

Site prep and building not included in this assessment, assumed that site prep was already performed and building 

already exists.

eTotal capital investment for an existing unit accounts for a retrofit factor of 1.15.

 

43 See Reference 23.

44 See Reference 13.
18

Table 9. Total Annual Cost for Condensers and Zero Emissions Dehydration Unit –

Transmission and Storage Source Category

Condenser

Zero Emiss 

Dehy

Direct Annual Costs (DAC)a

Operating labor 130 hours/yr x $technical labor rateb$3,960 $3,960 

Supervising labor 0.15 x Operating labor x management labor ratec937 937 

Operating materials None required 0 0 

Maintenance

 Labor 130 hours/yr x $technical labor rateb3,960 3,960 

 Material 0.50 x Maintenance laborc1,980 1,980 

Utilities Annual O&M associated with pumps assumed to be electrical 

costs (Range from $165 to $6,500 per yr for 28 MMscf/day

adjusted for avg dehy size) Nat. Gas STAR PRO FS 206

2,020 

DAC = $10,837 $12,857 

Indirect Annual Costs (IAC)a

Overhead 0.60 x Total labor plus Maintenance materials $5,314 $5,314 

Administrative 0.02 x TCIEd397 7,317 

Property tax 0.01 x TCIEd199 3,658 

Insurance 0.01 x TCIEd199 3,658 

Capital recoverye 0.1098 x TCIEd2,181 40,168 

IAC = $8,289 $60,116 

Total Net Annual Cost (DAC + IAC) $19,126 $72,973 

a

Procedures followed from OAQPS Control Cost Manual for calculating PEC and TCI (Reference 45).

bTechnical Labor Rate = $30.46/hr (Reference 46).

cManagement Labor Rate = $48.04/hr (Reference 47).

dTCIE from Table 67 for Condenser and Table 78 for zero emissions dehydrator.

eCapital recovery is based on equipment life of 15 years and an interest rate of 7%.

 

45 See Reference 24.

46 See Reference 26.

47 See Reference 26.
19

Table 10. Summary of Incremental Cost Effectiveness (ICE) Associated with Implementing 

a Zero Emissions Dehydration Unit at an Emission Reduction of 99.9 Percent

Cost Parameter

Oil and Natural Gas 

Production

Natural Gas 

Transmission and 

Storage

Number of large 

dehydration unitsa,b

92 15

Without Savings

Average ICE $17,597/ton $114,131/ton

With Savings

Average ICE $17,540/ton $114,070/ton

a Large dehydration units in the production source category are units with benzene emissions greater 

than 1 tpy and a natural gas throughput greater than 3 MMscf/day. Large dehydration units in the 

transmission and storage source category are units with benzene emissions greater than 1 tpy and a 

natural gas throughput greater than 10 MMscf/day.

b Number of large glycol dehydration units in the NEI dataset (see Attachments 3 and 4).
20

the natural gas transmission and storage source category, the average incremental cost 

effectiveness was $129,018/ton.

To estimate the cost savings resulting from the gas saved by implementing the zero emissions 

dehydrator, methane emissions were calculated relative to the HAP emissions. This analysis was 

conducted rather than using the values presented in the PRO Fact Sheet No. 206 because unit 

size data were not available for the 2005 NEI dataset and as a result, it is expected that lower 

HAP emitting units would be more likely to emit less methane. Therefore, the BID estimate for 

controlled units of 2,640 tpy of methane per 8,800 tpy of HAP48 was used to calculate a methane 

to HAP ratio of 0.3. This ratio was then applied to each dehydration unit to obtain an 

incremental reduction of methane emissions (we assumed that the same methane emission 

reductions relative to HAP are being achieved at the MACT level of control). Cost savings were 

estimated based on an average methane content of 79 percent for production49 and a natural gas 

cost of $4/Mscf.50 An average incremental methane savings of $255/yr was calculated. When 

calculated with savings, the average incremental cost effectiveness for the production source 

category was $17,993/ton. For the transmission and storage source category, the average 

incremental cost, considering savings, was $128,957/ton.

There are several uncertainties related to this cost analysis that would likely increase capital and 

annual costs, as follows:

 According to the PRO Fact Sheet No. 206, electric motors and controllers are used. 

However, no cost estimates were provided for sites that do not have electricity. It is 

presumed that oil and natural gas production facilities and natural gas transmission and 

storage facilities that are remotely located may not have available electricity and would 

be required to install an engine-turbine set, plus a backup system for when the primary 

system malfunctions. This uncertainty would result in an increase in the cost of the zero 

emissions technology.

 It was unclear whether an existing facility would be required to replace their existing 

equipment (e.g., condenser and flash tank) or whether their equipment would be able to 

be modified for use with the zero dehydrator system.

 It is also unclear from the PRO Fact Sheet No. 206, what additional equipment would be 

required for this system.

 The incremental cost represents a conservatively low estimate. We assumed that the 

stand-alone condenser plus flash tank cost was a sunk cost. However, it is possible the 

zero emission dehydrator cost would be added to the stand-alone condenser plus flash 

tank cost, resulting in an increase in annual cost and corresponding higher cost 

effectiveness calculation.

Based on these uncertainties, and the incremental cost effectiveness values (with and without 

savings), we determined that this technology is not technically and economically feasible for the 

large glycol dehydration unit subcategory in both production and transmission and storage.

 

48 See Reference 7. 

49 See Reference 13.

50Need a cost reference for gas prices.
21

Desiccant Dehydrators

Under certain operating conditions, desiccant dehydration units have been used by Natural Gas 

STAR partners to reduce HAP emissions by 99 percent. However, desiccant dehydration units 

are recommended when the wellhead gas temperature is low (less than 70oF) and the pressure is 

high (greater than 100 psig) and the volume of gas to be dried is 5 MMscf/day or less.

As the desiccant absorbs moisture from the gas, the operators periodically need to refill the 

desiccant. Refilling the desiccant bed is a manual operation that involves a backup dehydration 

unit, venting gas pressure from the primary unit to the atmosphere, opening the top filler hatch, 

and pouring desiccant pellets into the vessel. This requires the operator to dump one or more 30

to 50 pound bags of salt into the vessel, depending on dehydrator design. Because this procedure 

needs to be performed more frequently the higher the gas throughput, desiccant dehydrators are 

usually used when the volume of gas to be dried is 5 MMscf/day or less.51 No cost or operational 

data is provided for desiccant dehydration units to be operated natural gas throughputs higher 

than 5 MMscf/day.

According to the Lessons Learned document published by the Natural Gas STAR program, 

cooling or compressing the produced gas in order to use desiccant dehydrators increase system 

complexity and are typically cost prohibitive.

As shown in Attachment 2, all of the 63 glycol dehydration units in the production source 

category, for which we have data, have inlet gas temperatures greater than 70oF and 36 of the 63 

units have natural gas throughput greater than 5 MMscf/day. And, as mentioned previously, all 

of glycol dehydration units subject to the transmission and storage MACT standards have natural 

gas throughput greater than 10 MMscf/day. As a result, we do not believe desiccant dehydration 

generally could be used in these source categories and conclude that desiccant dehydration is not 

technically feasible for the units subject to standards in these source categories.

4.2.2 Improvements In Add-On Control Technology Or Other Equipment (That Was Identified 

And Considered During MACT Development)

As shown in Table 2, optimization of glycol circulation rate and installation of a flash tank 

separator are process modifications that are could reduce emissions. Optimization of the glycol 

circulation rate and installation of a flash tank separator were considered during MACT 

development.52 We do not have information to indicate that any significant improvement has 

occurred in these technologies. 

As summarized above, the subparts HH and HHH MACT standards generally require a 95 

percent emission reduction. Table 1 shows that two RBLC entries report emission reductions 

greater than 95 percent, one facility reports an emission reduction of 98 percent and another 

reports 99 percent.53 In addition, the State of Wyoming has a requirement that certain glycol 

 

51 See Reference 16

52 See Reference 7.

53 It is assumed that the baseline for these percent reductions is the reduction achieved in place of the use of a 

MACT-compliant control device.
22

dehydration units must reduce their emissions by 98 percent. The State of Wyoming assumes 

that the installation of a condenser and combustion device achieves 98 percent emission 

reduction as package but does not require monitoring or testing of these units. Both of these 

levels of control (98 and 99 percent) were evaluated.

To achieve further emission reductions beyond the MACT requirement of 95 percent reduction, 

an additional control device would most likely be required.54,55,56 Therefore, the incremental cost 

effectiveness was evaluated for adding a combustion device which would achieve an emission 

reduction of 98 percent or an emission reduction of 99 percent.

Cost data for a combustor were obtained from an analysis prepared for proposed state-only 

revisions to a Colorado regulation.57 Costs were escalated to 2008 dollars using the CE Indices 

for 2007 (525.4) and 2008 (575.4).58 The purchased equipment cost of a combustor, including an 

auto igniter and surveillance system was estimated to be $23,699 (escalated to 2008 dollars from 

$21,640 in 2007 dollars). The EIA did not include operating costs for the combustor. We believe 

that the operation of a combustor should require a level of effort similar to a condenser. 

Therefore, we have added 130 hours of operating labor, plus supervisory labor (15 percent of 

operating hours) plus maintenance labor (equal to operating labor). We documented our 

calculation of condenser labor requirements in a separate memorandum.59 Total capital 

investment, including freight and design and installation was estimated to be $32,301. These cost 

data are presented in Table 11. Total annual costs were estimated to be $19,580/year.

The cost effectiveness analysis is summarized in Table 12 and included in Attachment 4 for the 

production source category and in Attachment 5 for the transmission and storage source 

category. Again, it was assumed that all controlled large glycol dehydration units were subject to 

and controlled under subparts HH and HHH. Using this assumption, uncontrolled emissions were 

calculated using a 95 percent control efficiency, prior to use of the combustor. The incremental 

cost effectiveness for the combustor was calculated for each existing dehydration unit in the 

production source category. At a cumulative emission reduction of 98 percent, the average 

incremental cost effectiveness associated with production glycol dehydration units ranged from 

$360/ton to $204,918/ton, with an average of $45,620/ton. At an emission reduction of 99 

percent, the average incremental cost effectiveness associated with production glycol 

dehydration units ranged from $357/ton to $202,848/ton, with an average of $45,198/ton. For 

the transmission and storage source category, At an emission reduction of 98 percent, the 

 

54 Error! Main Document Only.Environment and Safety Business Unit, GRI. Investigation of Condenser 

Efficiency for HAP Control from Glycol Dehydrators Reboiler Vent Streams: Analysis of Data from the EPA 114 

Questionnaire and GRI’s Condenser Monitoring Program. March 1998.

55 Environment and Safety Research Group, GRI. Control Device Monitoring of Glycol Dehydrators: Condenser 

Efficiency Measurements and Modeling. January 1997. Volumes I and II.

56 Condensers have been shown to generally not be able to achieve emission reductions above 95 percent on an daily 

basis (see References 54 and 55). 

57 Initial Economic Impact Analysis for Proposed State-Only Revisions to the Air Quality Control Commission’s 

Regulation Number 7, “Emissions of Volatile Organic Compounds.” September 18, 2008. 

58 Economic Indicators: Chemical Engineering Plant Cost Index. Chemical Engineering Magazine. 

59Memorandum from Brown, H., EC/R Incorporated, to Moore, B., and Nizich, G., EPA/OAQPS/SPPD/FIG. Oil 

and Natural Gas Production MACT and Natural Gas Transmission and Storage MACT – Glycol Dehydrators: 

Impacts of MACT Review Options. July 28, 2011. Docket Number EPA-HQ-OAR-2010-0505-0047.
23

Table 11. Total Capital Investment and Total Annual Cost of a Combustor

Cost Itema

Capital 

Costs

($)

NonRecurring, 

One-time 

Costs ($)

Total 

Capital 

Investment 

($)b

O&M 

Costs ($)

Annualized 

Total Cost 

($/yr) c

Combustor $16,540

Freight and Design $1,500

Combustor Installation $6,354

Auto Igniter $1,500

Surveillance Systemd$3,600

Pilot Fuel $1,897

Operating Labor (includes 

management)e

$9,743

Maintenance $2,000

Data Management $1,000

Subtotal Costs (2007) $21,640 $7,854 $14,640

Subtotal Costs (2008) f$23,699 $8,601 $32,301 $16,033

Annualized costs (using 7% 

interest, 15 year equipment life)

$2,602 $944 n/a $19,580 

Minor discrepancies may be due to rounding

a Assume cost data provided is for the year 2007 (Reference 60).

b Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-time costs.

c Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and savings due to fuel 

sales.

d

Surveillance system identifies when pilot is not lit and attempt to relight it, documents the duration of time when 

the pilot is not lit, and notifies and operator that repairs are necessary.

e

Includes 130 hours/year of operating labor, 19.5 hours/year supervisory labor (15 percent of operating labor), and 

130 hours/year maintenance labor.

f Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4) (Reference 61.

 

60 Initial Economic Impact Analysis for Proposed State-Only Revisions to the Air Quality Control Commission’s 

Regulation Number 7, “Emissions of Volatile Organic Compounds.” September 18, 2008.

61 Economic Indicators: Chemical Engineering Plant Cost Index. Chemical Engineering Magazine.
24

Table 12. Summary of Incremental Cost Effectiveness (ICE) Associated with Raising the 

Emission Reduction to 98 Percent or 99 Percent

Cost Parameter

Oil and Natural Gas 

Production

Natural Gas 

Transmission and 

Storage

Number of large 

dehydration unitsa

92 15

Emission Reduction of 98 percent

Average ICE $45,659/ton $46,914/ton

Emission Reduction of 99 percent

Average ICE $45,198/ton $46,440/ton

a Large dehydration units in the production source category are units with benzene emissions greater 

than 1 tpy and a natural gas throughput greater than 3 MMscf/day. Large dehydration units in the 

transmission and storage source category are units with benzene emissions greater than 1 tpy and a 

natural gas throughput greater than 10 MMscf/day.
25

average incremental cost effectiveness associated with production glycol dehydration units 

ranged from $2,784/ton to $208,336/ton, with an average of $46,914/ton. At an emission 

reduction of 99 percent, the average incremental cost effectiveness associated with production 

glycol dehydration units ranged from $2,756/ton to $206,232/ton, with an average of 

$46,440/ton. 

Given the average and wide range of cost, we do not consider increasing the level of control 

from 95 to 98 or 99 percent to be economically feasible for large glycol dehydration units in 

these source categories. In addition, test data indicates that levels of control above 95 percent 

have not been shown to be reliably achieved in the field.62 Based on this analysis, we conclude 

that 98 and 99 percent control are neither technologically nor economically feasible at this time.

4.2.3 Work Practices and Procedures Not Identified and Considered During MACT 

Development

Table 2 presents several technologies that could be considered process modifications. These 

include: rerouting the glycol skimmer gas; routing the dehydration unit to a VRU; and replacing 

gas-assisted glycol pumps with electric pumps. As noted in Table 2, several of these process 

modifications would not be technically feasible for the majority of units in the large glycol 

dehydration unit subcategory: (1) Rerouting the glycol skimmer gas and routing the dehydration 

unit to a VRU would only be feasible provided there is a means by which the gas can be used;

(2) Replacing gas-assisted glycol pumps would require access to electricity, which would require 

remotely located sites to install additional equipment (including backup equipment) to generate 

electricity to operate these devices. Further, the documents presented by the Natural Gas STAR 

program do not provide emission reduction estimates by which a cost effectiveness evaluation 

could be conducted.

4.2.4 Process Changes or Pollution Prevention Alternatives That Could Be Broadly Applied 

Not Identified and Considered During MACT Development

Glycol dehydration units are a fairly unique process unit to the oil and natural gas sector. As a 

result, no broadly applicable process changes or pollution preventative alternatives were 

identified that have not already been considered.

5.0 TECHNOLOGY REVIEW FOR STORAGE VESSELS WITH THE POTENTIAL 

FOR FLASH EMISSIONS

Storage vessels with the potential for flash emissions refer to the collection of storage vessels 

that contain a hydrocarbon liquid with a stock tank gas-to-oil ratio (GOR) greater than or equal 

to 1,750 cubic feet per barrel (ft3/bbl), and an API gravity of greater than or equal to 40 degrees, 

and an actual average hydrocarbon liquid throughput of greater than or equal to 500 bbl/day. 

Flash emissions occur from these vessels when dissolved hydrocarbons evolve (or flash) from 

 

62 Comment submitted by William C. Allison V, Director, Air Pollution Control Division, Colorado Department of 

Public Health and Environment (CDPHE) (Supplemental comment to EPA-HQ-OAR-2010-0505-4191). Source 

Emissions Testing Report. ETC Canyon Pipeline, LLC. EPA Docket No. EPA-HQ-OAR-2010-0505-4469.
26

the tank contents when the fluid pressure is reduced. These storage vessels are located in the oil 

and natural gas production source category and typically store crude oil, condensate, or other 

hydrocarbon liquids at production facilities prior to transfer of the oil or natural gas to a refinery 

or natural gas processing plant. Condensate, also referred to as retrograde gas, consists of 

hydrocarbons that are in a gaseous state under reservoir conditions, but become liquid in either 

the wellbore or the production process.

This section presents the technology review conducted for storage vessels with the potential for 

flash emissions in the production source category. Section 5.1 presents a summary of level of 

control of the current MACT standards and the technologies evaluated during the development 

of those standards. Section 5.2 presents an analysis for identified control technologies to 

determine whether they qualify as “developments in practices, processes, and control 

technologies” for these source categories under section 112(d)(6).

5.1 Summary of Existing MACT Level of Control

The storage vessel MACT standards promulgated in the 1999 NESHAP (subpart HH) require 

that emissions of HAP from storage vessels with the potential for flash emissions be controlled 

using a cover that is connected to a closed vent system.63 The closed vent system is required to 

operate with no detectable emissions. The captured HAP emissions are then required to be routed 

to a control device or series of control devices that reduce the HAP mass emissions by 95 

percent. Storage vessels with the potential for flash emissions can also comply with subpart HH 

by using a pressure storage vessel that is designed to operate with no detectable emissions at all 

times.

During the development of the 1999 MACT standard, the control options considered for storage 

vessels with the potential for flash emissions included vapor collection with a closed vent system 

either routed to the process or routed to a combustion device.64 Internal floating roof tanks were 

not considered technically feasible for storage vessels with the potential for flash emissions 

because internal friction between the floating roof and the interior of the sizes of tanks typical for 

the source category would inhibit proper operation of the floating roof. In addition, the small 

quantities of liquid stored in these types of tanks typically do not provide sufficient buoyancy to 

support floating roofs. 

To evaluate impacts of potential controls, we used the 2005 NEI dataset (Attachment 6), which 

we believe contains the most current emissions data. 

5.2 Developments in Technology for Storage Vessels with the Potential for Flash

Emissions

The practices, processes, and control technologies that were considered during the MACT 

development for storage vessels with the potential for flash emissions included: a closed vent 

system either routed to the process or to a combustion device. A search of the RBLC database 

 

63 The closed vent system can also be considered a vapor recovery unit, which is designed to collect vapors and 

either route the vapors to a control device or back to the natural gas line (See Reference 7).

64 See Reference 7.
27

did not identify any control technologies that achieved a level of control greater than 95 percent 

(see Attachment 1). Table 13 presents a search of the Natural Gas STAR program for storage 

vessels. Table 14 presents a search of State regulations that are more stringent than the MACT 

requirements. Since the MACT standard for storage vessels with the potential for flash emissions 

95 percent emission reduction, we focused the technology review on developments that would 

achieve greater than 95 percent emission reduction. In addition, the EPA can consider cost in its

section 112(d)(6) review. The next sections address how the EPA considered potential

developments in practices, processes, and control technologies for the subpart HH MACT 

standards for storage vessels with PFE.

5.2.1 Add-on Control Technology or Other Equipment Not Identified and Considered during 

MACT Development

As previously stated, the technologies considered during MACT development of the 95 percent 

emission reduction requirement included a closed vent system (which operates with no 

detectable emissions) and a control device that achieves a 95 percent control efficiency. No new 

equipment or control technologies were identified that were not considered during MACT 

development.

5.2.2 Improvements in Add-on Control Technology or Other Equipment (that was Identified 

and Considered During MACT Development)

As summarized above, the subpart HH standards generally require a 95 percent emission 

reduction. Based on our review of the RBLC and information from the Natural Gas STAR 

program, none of the technologies reported achieve an emission reduction greater than 95 

percent. 

As shown in Table 13, some Natural Gas STAR partners report the installation of pressurized 

storage vessels for condensates. Pressurized storage vessels were identified as a potential control 

technology during the development of the MACT standard.65 According to the MACT floor 

memorandum for the 1999 standards,66 natural gas liquids consisting of ethane, propane, and 

butane, and natural gasoline are typically stored in pressurized storage tanks because of their 

high volatility. Pressurized storage tanks are designed to operate as closed systems and are 

usually located at natural gas processing plants and are considered unique from those storage 

tanks that are operated at or near atmospheric pressure conditions. Therefore, because 

pressurized tanks are (1) used in special situations and (2) designed as closed systems, 

pressurized tanks were not considered in determining the MACT floor for storage tanks operated 

at or near atmospheric pressure conditions. However, because of their closed-system design, 

pressurized tanks are considered to be in compliance with any requirements for storage tanks 

operated at or near atmospheric conditions. As such, pressurized tanks are allowed as a 

compliance option under subpart HH. As discussed elsewhere in this document, EPA is not 

required in a review under section 112(d)(6) to correct an alleged deficiency in an underlying 

MACT standard. Further, the Natural Gas STAR report does not provide information to 

determine whether the use of a pressurized storage tank would be technically feasible for a liquid 

 

65 See Reference 7.

66 See Reference 5.
28

Table 13. Natural Gas STAR Program Storage Vessel With the Potential for Flash Emissions Control Technologies

Control 

Technology Description Reported Applicability

Type of Control 

Technology

Associated

Gas Savings 

(Mcf)67

Comments on Control 

Technology Ref

Installing 

Vapor 

Recovery 

Units on 

Storage tanks

VRUs capture gases flashed from crude 

oil or condensate

Gases can be recovered for sales, fuel 

for onsite operation, or piped to a 

stripper to separate NGLs and methane 

to recover NGLs.

Gases can be flared if recovered gases 

cannot be used

Captures about 95 percent of BTU-rich 

vapors

Requires a steady state source 

and adequate quantity of crude 

oil or condensate vapors along 

with an economic outlet for 

the collected product.

Equipment 4,900 –

96,000

Main components are 

suction scrubber, 

compressor, and 

automated control unit.

68

Install Flares Flares installed to combust gases from 

tanks

Can be applied to all point 

source vented emissions

Equipment None No information is 

provided on HAP or 

VOC reduction

69

Install 

Pressurized 

Storage of 

Condensate

Install pressurized storage tanks All gas well and 

gathering/booster compressors

Equipment 7,000 No information is 

provided on HAP or 

VOC reduction

70

Eliminate 

Unnecessary 

Equipment 

and/or 

Systems

Eliminate or downgrade unnecessary 

pieces of equipment or systems; 

consolidate and centralize liquid 

storage facilities

Only applies to facilities well 

below design rates

Process 

modification

4,200 71

 

67 Gas savings reported for technologies, but no information is available in the Natural Gas STAR documents to indicate what percent reduction this represents.

68 EPA (2006) Lessons Learned: Installing Vapor Recovery Units on Storage Tanks. Natural Gas STAR

69 EPA (2011) Partner Reported Opportunities: Install Flares. PRO Fact Sheet No. 904.

70 EPA (2011) Partner Reported Opportunities: Install Pressurized Storage of Condensate. PRO Fact Sheet No. 501.

71 EPA (2011). Partner Reported Opportunities: Eliminate Unnecessary Equipment and/or Systems. Natural Gas STAR.
29

with a stock tank GOR greater than or equal to 1,750 ft3/bbl, and an API gravity of greater than 

or equal to 40 degrees, and an actual average hydrocarbon liquid throughput of greater than or 

equal to 500 bbl/day. Therefore, we do not consider this an improvement in technology.

As identified in Table 13, Natural Gas STAR partners report the use of VRUs on storage vessels 

to capture about 95 percent of the vapors. As stated previously, the MACT floor was determined 

to be a 95 percent emission reduction. Therefore, we do not consider this an improvement in 

technology.

Insufficient data are provided to assess whether the flare technology reported by the Natural Gas 

STAR program achieves an emission reduction greater than 95 percent. However, Table 14 

shows that the State of Wyoming requires a 98-percent emission reduction for storage vessels. 

Therefore, incremental cost effectiveness was evaluated to determine whether increasing the 

emission reduction from 95 percent to 98 percent was economically feasible for storage vessels. 

To do this, we assumed that oil and natural gas production facilities would have installed VRUs 

to achieve the 95 percent emission reduction required under subpart HH. To achieve an emission 

reduction of 98 percent, we assumed a combustion device would achieve an emission reduction 

of 98 percent.

Cost data for a combustor is presented in Table 12. We assumed that facilities would install one 

control device for every four tanks or fewer (e.g., a facility with 10 tanks would install 3 control 

devices). Total capital investment, including freight and design and installation was estimated to 

be $32,301. These cost data are presented in Table 12. Total annual costs were estimated to be 

$19,580/year.

To estimate costs associated with the MACT level of control, it was assumed that facilities had 

installed VRUs. Table 15 presents the cost data for a VRU. Similar to combustors, this data was 

obtained from the Initial EIA prepared for proposed state-only revisions to the Colorado 

regulation.72 The TCI for a VRU is $98,186 and the TAC is $18,983/yr.

The cost effectiveness analysis is summarized in Table 16 and included in Attachment 6. Again, 

it was assumed that all controlled storage vessels in the 2005 NEI were storage vessels with the 

potential for flash emissions and therefore subject to and controlled under subpart HH. Using this 

assumption, uncontrolled emissions from each storage vessel were calculated using a 95 percent 

control efficiency. The incremental cost effectiveness was calculated for each existing storage 

vessel. At an emission reduction of 98 percent, the average incremental cost effectiveness 

associated with storage vessels was $81 million/ton. Given the average cost effectiveness, we did 

not consider increasing the level of control to 98 percent to be economically feasible.

 

72 See Reference 24.
30

Table 14. Hydrocarbon Liquids Storage Vessel Regulations (Greater than 95% Control)

State Source Applicability Standard Compliance Options

WY New and Existing Sources;

≥0-20 tpyVOC (depending on 

attainment status)

98 % -Install VR device that reduces 

the mass content of VOCs and 

HAPs by at least 98 %

-Enclosed, smokeless 

combustion device (e.g., thermal 

vapor incinerator, boiler or 

process heater) or flare that 

reduces the mass content of 

VOCs and HAPs by at least 

98 percent

-Any other control device that 

can be demonstrated to reduce 

the mass content of VOCs and 

HAPS by at least 98 percent by 

weight.

-May remove after one year if 

VOC emissions less than 8 tpy

(depending on location)
31

Table 15. Total Capital Investment and Total Annual Cost of a Vapor Recovery Unit

Cost Itema

Capital 

Costs

($)

NonRecurring, 

One-time 

Costs ($)

Total 

Capital 

Investment 

($)b

O&M 

Costs ($)

Savings 

due to Fuel 

Sales 

($/yr)

Annualized 

Total Cost 

($/yr) c

VRU $78,000

Freight and Design $1,500

VRU Installation $10,154

Maintenance $8,553

Recovered natural gas ($1,063)

Subtotal Costs (2007) $78,000 $11,654 $8,553 ($1,063)

Subtotal Costs 

(2008)d

$85,423 $12,763 $98,186 $9,367 ($1,164)

Annualized costs 

(using 7% interest, 15 

year equipment life)

$9,379 $1,401 n/a n/a $18,983

Minor discrepancies may be due to rounding

a Assume cost data provided is for the year 2007 (Reference 73).

b Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one-time costs.

c Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and savings due to fuel 

sales.

d Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4) (Reference 74).

 

73 See Reference 60.

74 See Reference 23. 
32

Table 16. Summary of Incremental Cost Effectiveness (ICE) Associated with Raising the 

Emission Reduction to 98 Percent

Cost Parameter

Oil and Natural Gas 

Production

Number of facilities 174

Average ICE $81.3 million/ton
33

5.2.3 Work Practices and Procedures Not Identified and Considered During MACT 

Development

One procedure identified beyond what was considered during MACT development was the 

elimination of unnecessary equipment or systems, in particular, the consolidation and 

centralization of liquid storage facilities. This would not be technically feasible for many 

facilities with storage vessels that are remotely located. As a result, we did not consider 

consolidation of liquid storage facilities to be technically feasible.

5.3.3 Process Changes or Pollution Prevention Alternatives That Could Be Broadly Applied 

Not Identified and Considered During MACT Development

No broadly applicable process changes or pollution preventative alternatives were identified that 

have not already been considered.

6.0 TECHNOLOGY REVIEW FOR EQUIPMENT LEAKS

Equipment leaks are emissions emanating from valves, pump seals, flanges, compressor seals, 

pressure relief valves, open-ended lines, and other process and operation components. The 

amount of HAP emissions from equipment leaks is proportional to the type and number of 

equipment components, and the concentration of HAP constituents of the stream passing through 

the components. 

This section presents the technology review conducted for equipment leaks in the oil and natural 

gas production source category. Section 6.1 presents a summary of level of control of the current 

MACT standards and the technologies evaluated during the development of those standards. 

Section 6.2 presents other technologies identified by the EPA and by commenters for equipment 

leaks. Section 6.3 presents an analysis for each of these other technologies to determine whether 

they qualify as “developments in practices, processes, and control technologies” for these source 

categories under section 112(d)(6).

6.1 Summary of Existing MACT Level of Control

The equipment leaks MACT standards promulgated in the 1999 NESHAP (subpart HH) apply to 

the group of all ancillary equipment,75 except compressors, intended to operate in volatile HAP 

(VHAP)76 service which are located at natural gas processing plants (NGPP) and compressors 

intended to operate in VHAP service, which are located at NGPP [§63.760(b)(1)(iii) and (iv)]. 

The provisions of subpart HH apply to ancillary equipment and compressors that operate in 

 

75 Ancillary equipment is defined in subpart HH (§63.761) as any of the following pieces of equipment: pumps, 

pressure relief devices, sampling connection systems, open-ended valves or lines, valves, flanges, or other 

connectors.

76 In VHAP service is defined in subpart HH (§63.761) as a piece of ancillary equipment or compressor either 

contains or contacts fluid (liquid or gas) which has a total VHAP concentration equal to or greater than 10 percent 

by weight.
34

VHAP service 300 hours per calendar year or more. Each piece of ancillary equipment and each 

compressor subject to subpart HH is required to comply with specific provisions of 40 CFR, 

part 61, subpart V:

 Valves in gas and vapor service: conduct monthly EPA Method 21 monitoring and leak 

definition of 10,000 ppm.

 Connectors: sensory monitoring;

 Pressure relieve devices in gas/vapor service: operate with no detectable emissions (i.e., 

less than 500 ppm) or equipped with a rupture disk / or routed to an air pollution control 

device; and

 Open ended lines: equip with a cap or comparable. 

During the development of the 1999 MACT standard, the control options evaluated were 

implementation of a leak detection and repair (LDAR) program and modification or replacement 

of existing equipment to reduce emissions. 

6.2 Developments in Technology for Equipment Leaks from Ancillary Equipment and 

Compressors

The practices, process and control technologies that were considered during MACT development 

for equipment leaks from ancillary equipment and compressors located at natural gas processing 

plants included LDAR and equipment modification or replacement. On February 24, 2012, the 

EPA proposed a set of emissions standards, known as Uniform Standards (US), for equipment 

leaks. Once finalized, the Uniform Standards, known as Uniform Standards (US), may be 

referenced by source-category specific NESHAP. During the development of the proposed US, 

the EPA issued a memorandum (US equipment leak memorandum) that documents analyses of 

control options for equipment leaks and presents an analysis of several alternative means of 

compliance, using a model plant approach.77 Information summarized in the US memorandum 

was relevant and therefore was used in the technology review for equipment leak standards under 

subpart HH.

No entirely new developments in methods for controlling equipment leak emissions were 

found.

78 Since the 1999 MACT, the following variations and advancements in existing 

technologies and practices that were not currently required in subpart HH were identified: (1) 

optical gas imaging (OGI); (2) “low leak” packings; and (3) monitoring of new equipment. In 

addition to these advancements, we also identified at least two local regulatory authorities in 

California (Bay Area Air Quality Management District, BAAQMD, and South Coast Air Quality 

Management District, SCAQMD) that place a limit on the total number of non-repairable 

equipment allowed. Each of these variations in technologies and practices as they apply to 

NGPP are addressed below. Finally, we will address the alternative means of compliance 

presented in the US memorandum as it applies to NGPP.

Optical Gas Imaging

 

77 Memorandum from Hancy, C., RTI International, to Howard, J., EPA/OAQPS. Analysis of Emission Reduction 

Techniques for Equipment Leaks. December 21, 2011. EPA Docket No. EPA-HQ-OAR-2010-0869-0029.

78 See Reference 77.
35

The EPA identified OGI during the development of the proposed US as a potential advancement 

in existing technologies and practices not currently required in existing EPA rules. Optical gas 

imaging devices offer the ability to monitor equipment from a distance and identify leaks (of a 

sufficient mass) from equipment within the line of sight of the optical imager.79 The General 

Provisions for NESHAP at 40 CFR 63.11(c) allow as an alternative to a traditional LDAR

monitoring program (e.g., EPA Method 21) the use of the AWP under 40 CFR 63.11(c), which 

allows the use of OGI along with an annual EPA Method 21 survey of all of the equipment. The 

US proposal would allow OGI as an alternative if allowed by a referencing subpart and only if 

the yet-to-be issued OGI protocol is followed. While this technology appears to be technically 

feasible, the necessary protocol has not been issued by the EPA and as a result, we believe OGI 

is not appropriate for adoption at this time in subpart HH. The EPA intends to re-evaluate the 

use of OGI as a permissible alternative in subpart HH after the protocol is published.

Low Leak Packing

According to information in the US memorandum, packing combinations for valves and gaskets 

for flanges that significantly reduce emissions are in place in some facilities, particularly oil 

refineries. Facilities and packing manufacturers have created emission testing protocols for low 

leak packing in order to study and test their effectiveness. This technology appears to be 

technically feasible, however, we do not have the data to assess the economic feasibility of 

requiring the installation of these types of equipment and when to require their installation.

Monitoring of Equipment

Some local regulations have requirements for monitoring equipment that have not been required 

to be monitored in the past. For example, monitoring of open ended valves and lines (OELs) and 

atmospheric pressure release valves (PRVs).80

The South Coast Air Quality Management District (SCAQMD) requires continuous monitoring 

of a percentage of atmospheric PRDs at refineries by installing a monitoring device capable of 

recording the duration of each release and quantifying emissions. Wireless technology allows 

continuous monitoring of PRDs and makes it easier for operators to identify releases and leaks. 

There are several monitoring devices that can be used, including acoustic sensors and 

pressure/differential pressure sensors. These sensor units communicate with a base radio that 

interfaces with the existing control system.

81

For the cost analysis for monitoring of OEL and PRDs, it was assumed that no additional 

emissions reductions will be provided since OELs are required to be capped under the 1999 

MACT standards.82 Costs would be associated with additional monitoring and repair. Likewise, 

it was assumed that no additional emission reductions would occur from wireless monitoring of 

PRDs since they are required to operate with no detectable emissions under the 1999 MACT 

 

79 See Reference 77.

80 See Reference 77.

81 See Reference 77.

82 See Reference 77.
36

standards. However, additional capital costs would be incurred. As a result, we estimate no 

emissions reductions from these practices.

Local District Limits on Number of Components Awaiting Repair

The BAAQMD Regulation 8, Rule 18 limits the number of components awaiting repairs to 

0.3 percent for valves, 0.025 percent for valves with major leaks (i.e., leaks greater than 10,000 

ppm, including methane) and 1.0 percent for pumps and compressors. BAAQMD also requires 

mass emission testing for non-repairable components with high leak rates and places an emission 

limit of 15 lbs/day on non-repairable components. The SCAQMD Rule 1173 limit is 0.5 percent 

for valves and 1.0 percent for pumps.

Background data for the proposed amendments to BAAQMD Regulation 8 Rule 18 provides

incremental costs associated with their amendment that lowers the number of components 

awaiting repairs from 0.5 percent for valves and 1.0 percent for pumps, compressors, and 

pressure relief devices to 0.3 percent for valves and 1.0 percent for pumps, compressors, and 

pressure relief devices.

83 According to this report, BAAQMD estimates that the incremental 

emission reduction associated with their amendment would be 74 tpy of total organic compounds 

(TOC). The incremental annual costs associated with the amendment were estimated to range 

from $23,500 to $118,000 per year, resulting in a cost effectiveness ranging from $320 to $1,600 

per ton of TOC. Using an average gas composition for equipment leaks of 0.00728 lb HAP/lb 

TOC,84 the associated HAP emission reduction for the proposed BAAQMD amendments is 

0.539 tpy HAP and the cost effectiveness ranges from $43,600 to $219,000 per ton HAP. No 

additional cost and emission data were identified to determine what the incremental costs 

associated with applying this approach to the 1999 subpart HH level of control. Based on this 

lack of additional information and the incremental cost effectiveness calculated for the proposed 

BAAQMD amendments, we do not consider implementation of BAAQMD-level limits on 

components awaiting repairs to be economically feasible.

Alternative Means of Compliance by Component Type and for Entire LDAR Program

As stated above, the LDAR program under the 1999 MACT standards is equivalent to 40 CFR 

part 61, subpart V, which is equivalent to the VOC new source performance standards under 40 

CFR part 60, subpart VV. More recent regulations have been issued that are more stringent than 

subpart V. In November 2007, the EPA issued 40 CFR part 60, subpart VVa, which: lowered the 

leak definition for valves to 500 ppm; and requires monitoring for connectors with a new leak 

definition of 500 ppm. In addition, the BAAQMD equipment leak standards85establish a leak 

definition of 100 ppm for valves and connectors.

 

83 Douglas, Victor, Compliance and Enforcement Division, BAAQMD. Draft Staff Report: Proposed Amendments 

Regulation 8 Rule 18: Equipment Leaks Control Measure SS-16. December 2003.

84 Memorandum from Brown, H.P., EC/R Incorporated, to Moore, B., EPA/OAQPS/SPPD. Composition of Natural 

Gas for use in the Oil and Natural Gas Sector Rulemaking. July 28, 2011. EPA Docket No. EPA-HQ-OAR-2010-

0505-0084.

85 BAAQMD. Regulation 8, Organic Compounds, Rule 18 – Equipment Leaks.
37

The levels of control in the more recent regulations were evaluated in the US memorandum. To 

calculate cost estimates and emissions reductions for various control options in the US 

memorandum, model plants were developed to represent equipment counts found at different 

types of chemical and refining facilities. Similar to the US approach, we developed model plants 

for equipment leaks at NGPP in the oil and natural gas production source category. Table 17 

presents the model plant component counts for NGPP.86 In order to assess the cost effectiveness 

of different compliance options, we determined that Model Plant 5 in the US memorandum most 

closely represents the NGPP model plant (see Table 17). Because Model Plant 5 in the US 

memorandum represents a refinery with pieces of equipment in gas/vapor service, light liquid 

service, and heavy liquid services, all pieces of equipment from US Model Plant 5 are not 

included in the NGPP analysis. For a NGPP in the oil and natural gas production source 

category, the types of equipment included in this analysis are as follows: valves in gas/vapor 

service; connectors in gas/vapor service; pressure relief devices; and open-ended lines. 

Table 18 presents a summary of the equipment leak requirement options that were analyzed. 

These options were developed to match current regulatory requirements for facilities subject to 

certain existing rules. For valves, requirement options include lowering the leak definition to 

500 ppm, which is consistent with 40 CFR part 60, subpart VVa (Valve Option 1) and lowering 

the leak definition to 100 ppm (Valve Option 2), which is consistent with some local 

requirements, such as the BAAQMD equipment leak standards. For connectors, consistent with 

subpart VVa, the requirement option explored was to add instrument monitoring for connectors 

with a leak definition of 500 ppm. Connectors had not previously been required to be monitored 

under 40 CFR part 61, subpart V. 

As shown in Table 18, it was assumed that options considered for OEL and PRDs did not result 

in any emission reductions. As a result, cost effectiveness was not calculated for these types of 

equipment. Table 19 presents a summary of the cost analysis performed for valves in gas/vapor 

service and connectors in gas/vapor service. This analysis was conducted using the approach

documented in the technical support document for the Oil and Gas Sector NSPS. 87 For valves in 

gas/vapor service, reducing the leak definition to 500 ppm has an incremental cost effectiveness 

of $4,671/ton. Reducing the leak definition further, to 100 ppm, the incremental cost 

effectiveness was estimated to be $14,060/ton. The incremental cost effectiveness associated 

with instrument monitoring of connectors in gas/light liquid service (with a leak definition of 500 

ppm) was $18,283/ton. Based on these estimates, reducing the leak definition for valves to 500 

ppm is cost effective. However, we do not believe that reducing the leak definition for valves to 

100 ppm or instrument monitoring of connectors with a 500 ppm leak definition is cost effective.

 

86 EC/R Incorporated, Chapel Hill, NC. Prepared for U.S. Environmental Protection Agency. Oil and Natural Gas 

Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution -

Technical Support Document. July 2011. EPA-453/R-11-002. EPA Docket No. EPA-HQ-OAR-2010-0505-0045.

87 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, 

and Distribution. Background Supplemental Technical Support Document for the Final New Source Performance 

Standards. April 2012.
38

We also evaluated the costs of implementing a subpart VVa-level of control for NGPP. This 

evaluation is documented in the technical support document for the final rule.88 The incremental 

capital costs associated with increasing the LDAR program level of control from subpart VV to 

subpart VVa were estimated to be $8,041 per facility. The annual costs were estimated to be 

$8,462/yr (which includes recovery credits). With a HAP emission reduction of 0.172 tpy, the 

incremental cost effectiveness was $49,256/ton.

 

88 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, 

and Distribution. Background Supplemental Technical Support Document for the Final New Source Performance 

Standards. April 2012.
39

Table 17. Model Plants for NGPP

Equipment Component

Number of 

Pieces of 

Equipment 

Valves (gas/vapor service) 1392

Connectors (gas/vapor 

service)

4392

Pressure relief devices 29

Open ended lines 134
40

Table 18. Summary of Equipment Leak Requirement Options89

Type of 

Equipment

Requirements of 

1999 MACT 

Standards Alternative Options Additional Requirements

Valves Monthly Method 12 

monitoring; leak 

definition of 10,000

Valve Option 1 Lowers leak definition of gas/light liquid valves 

to 500 ppm

Valve Option 2 Lowers leak definition of gas/light liquid valves 

to 100 ppm

Connectors Sensory Monitoring Connectors Option 1 Adds instrument monitoring for gas/light liquid 

connectors at 500 ppm

Open-ended 

lines

Equip with cap or 

comparable 

OEL Conduct annual instrument monitoring to 

demonstrate that the OEL operates with an 

instrument reading of 500 ppma

Pressure Relief 

Devices

Operate with no 

detectable emissions 

(500 ppm) or install 

rupture disk or route to 

air pollution control 

device.

PRD Wireless monitoring of PRDsb

a

It was assumed that no additional emissions reductions will be provided since OELs are required to be capped 

under the 1999 MACT standards. Costs would be associated with additional monitoring and repair.

b

It was assumed that no additional emission reductions would occur from wireless monitoring of PRDs but 

additional capital costs would be incurred. 

 

89 See Reference 77.
41

Table 19. Summary of Cost Effectiveness Analysis for Valves and Connectors

Type of equipment Cost Parameter Baseline

Option 1 

(Incremental 

from Baseline)a

Option 2 

(Incremental 

from Option 1)b

Valves in gas/vapor service HAP Emissions 0.114 tpy 0.045 tpy 0.011 tpy

Emission Reduction -- 0.069 tpy 0.034 tpy

Total Annual Costc$64,280 $66,119 $68,340

Incremental Annual 

Costd

-- $321/yre$1,464

Cost Effectivenessf-- $4,671/ton $42,794/ton

Connectors Emissions 0.166 tpy 0.063 tpy

Emission Reduction -- 0.103 tpy

Total Annual Costc--

g

$1,887

Incremental Annual 

Costd

$1,887e

Cost Effectivenessf-- $18,293/ton

Minor discrepancies are due to rounding.

aOption 1 for valves is a reduced leak definition of 500 ppm. Option 1 for connectors is the addition of monitoring of 

connectors and a leak definition of 500 ppm. Emissions and cost data extracted from US memorandum and are 

summarized in Attachment 7.

b Option 2 for valves is a reduced leak definition of 100 ppm. No option 2 was considered for connectors.

c

See Attachment 7.

d

Incremental annual cost is calculated using the following formula:

 

 

 

 

 

 

 

 

 

 

 

 

e

Includes recovery credits which are calculated as based on methane reductions and $4/Mcf.

f

Incremental cost effectiveness is calculated using the following formula:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

gNo annual costs are associated with connectors at baseline.
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 DIESEL STORAGE 

TANK, UNIT NO. 19

42.005 3060 BBL THE PERMIT DOES NOT INDICATE WHETHER THE TANK IS FIXED OR 


FLOATING ROOF. SCC AND PROCESS CODES CHOSEN ARBITRARILY 


FOR PURPOSES OF THIS DATABASE.

Volatile Organic Compounds 

(VOC)

P PERMITTEE MUST 

FOLLOW MONITORING 

AND RECORD 


KEEPING PROVISIONS 

FOR VOC ESTABLISHED 

UNDER 40 


CFR 60, SUBPART KB.

0 0

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 INCINERATOR, UNIT 

9

50.999 1.6 MMBTU/H** *TYPICAL FUEL LISTED FOR PROCESS INCLUDES NATURAL GAS, 


WASTE, AND DIESEL FUEL. SCC CODE IS FOR INCINERATORS 


BURNING WASTE GAS OR AUGMENTED WASTE GAS. 


**THROUGHPUT WHEN BURNING: WASTE IS 438 TONS, NATURAL GAS 


IS 1.6 MMBTU/H, DIESEL, 1.6 MMBTU/H. 


MAXIMUM OPERATION DURING: PRE-SEALIFT PERIOD, 8760 H


(BURNING WASTE), 8760 H (BURNING NATURAL GAS), 8760 H 


(BURNING DIESEL); COMMISSIONING PERIOD, 1848 H (BURNING 


WASTE); 1848 H (BURNING NATURAL GAS), 1848 H (BURNING 


DIESEL); AFTER COMMISSIONING PERIOD, 8760 H/YR (BURNING 


WASTE), 8760 H/YR (BURNING NATURAL GAS), 0 H/YR FOR 


DIESEL.

Volatile Organic Compounds 

(VOC)

A SECONDARY COMBUSTION CHAMBER. 0 0

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 HP FLARE, UNIT NO 

11

19.33 0.08 MMSCF/D** *PROCESS USES NATURAL GAS AND PRODUCED GAS AS FUEL. SCC 


CODE PROVIDED IS FOR CRUDE OIL PRODUCTION. SCC CODE FOR 


NATURAL GAS PRODUCTION IS 31000205.


 


GAS IS 30600904.


**ADDITIONAL RATING- 600 MMSCF/D. RATINGS PROVIDED FOR 


PILOT/PURGE GAS RATE AND MAXIMUM FLARE CAPACITY.


MAXIMUM OPERATION DURING COMMISSIONING PERIOD; 1848 H, 


MAXIMUM OPERATION AFTER COMMISSIONING PERIOD, 8760 H/YR.

Volatile Organic Compounds 

(VOC)

A GAS-ASSIST SMOKELESS FLARE TECHNOLOGY. 0 0

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 LP FLARE (NATURAL 

GAS), UNIT 12

19.33 0.02 MMSCF/D LP FLARE ALSO BURNS PRODUCED GAS, LISTED SEPARATELY.


MAXIMUM OPERATION DURING COMMISSIONING PERIOD, 1848 H; 


MAXIMUM OPERATION AFTER COMMISSIONING PERIOD; 8760 H/YR.


SCC CODE IS FOR CRUDE OIL PRODUCTION. SCC CODE FOR 


NATURAL GAS PRODUCTION IS 31000205.

Volatile Organic Compounds 

(VOC)

A GAS-ASSIST SMOKELESS FLARE TECHNOLOGY 0 0

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 LP FLARE 

(PRODUCED GAS), 

UNIT 12

19.33 0.43 MMSCF/D LP FLARE ALSO BURNS NATURAL GAS, LISTED SEPARATELY. 


MAXIMUM OPERATION DURING AND AFTER COMMISSIONING PERIOD, 


720 H; SCC CODE IS FOR CRUDE OIL PRODUCTION. SCC CODE FOR 


NATURAL GAS PRODUCTION IS 31000205.

Volatile Organic Compounds 

(VOC)

A GAS-ASSIST SMOKELESS FLARE TECHNOLOGY 0 0

AK-0038 NORTHSTAR 

DEVELOPMENT 

PROJECT

AK 1311 211110 RIG ENGINES, 

CATERPILLAR G399, 

UNIT 200-204

17.13 930 HP TYPICAL OPERATION DURING PRE-SEALIFT PERIOD, 2568 H. 


TYPICAL OPERATION DURING COMMISSIONING PERIOD, 24 H EACH. 


TYPICAL OPERATION AFTER COMMISSIONING PERIOD, 700 H/YR. 


UNDER NORMAL LONG-TERM OPERATIONS, THE RIG ENGINES WILL 


NOT BE OPERATED. OPERATION OF THESE ENGINES IS UNDER AN 


ALTERNATIVE OPERATION SCENARIO.

Volatile Organic Compounds 

(VOC)

A CATALYTIC OXIDATION TECHNOLOGY0 0

AK-0047 MILNE POINT 

PRODUCTION 

FACILITY

AK 1311 211111 TANK, T-6101A 42.005 147000 GAL Volatile Organic Compounds 

(VOC)

P COMPLIANCE WITH 

THE RECORDKEEPING 

PROVISIONS OF 


40 CFR SUBPART KB.

0 0

AK-0047 MILNE POINT 

PRODUCTION 

FACILITY

AK 1311 211111 TANK, T-2002 64.004 11800 GAL Volatile Organic Compounds 

(VOC)

P COMPLIANCE WITH 

THE RECORDKEEPING 

PROVISIONS OF 


40 CFR SUBPART KB.

0 0

Attachment 1, page 1 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

AK-0047 MILNE POINT 

PRODUCTION 

FACILITY

AK 1311 211111 VENTS 50.002 UNITS CATEGORIZED AS VENTS AND INCLUDED IN THIS ENTRY 


INCLUDE: OIL RESERVE TANKS; VENT HEADER (FLOTATION CELLS, 


COMPRESSOR VENTS, TEG REBOILER, DRAIN PURGE, VENT PURGE 


GAS, BACKWASH CLARIFIER, PRODUCED WATER SURGE TANK, TANK T-


5853, AND SAND SLURRY TANK); OTHER TANKS (T-2001, T-6102A, 


T-6102B).

Volatile Organic Compounds 

(VOC)

P GAS BLANKETING AND 

BACK PRESSURE 

RELIEF VALVE 


FOR OIL RESERVE 

TANKS. WITHIN 60 D 

OF ISSUANCE, 


DO NOT VENT GAS TO 

ATMOSPHERE FROM 

PRODUCED 


WATER SURGE TANK. 

ISOLATE PRESSURE 

CONTROL 


VALVE.

0 0

AL-0072 MOBIL OIL 

EXPLORATION & 

PRODUCING 

SOUTHEAST, INC.

AL 1311 211111 MATL. HANDLING, 

HEAVY 

HYDROCARBON 

LOADING

50.004 0 Volatile Organic Compounds 

(VOC)

A VAPOR RECOVERY WITH FLARE 0 95

AL-0073 MOBIL OIL 

EXPLORATION & 

PRODUCING 

SOUTHEAST, INC.

AL 1311 211111 MATL. STORAGE, 

CONDENSATE & 

CIO FLUID

50.004 0 Volatile Organic Compounds 

(VOC)

A VAPOR RECOVERY WITH FLARE 0 95

AL-0144 SNG - ELMORE 

COMPRESSOR 

STATION

AL 4922 486210 ENGINE, IC 5000 HP 

VERTICAL 

RECIPROCATING

17.13 5000 HP Volatile Organic Compounds 

(VOC)

N 1.3 G/B-HP-H 0 Y

AL-0171 MOBIL OIL 

EXPLORATION & 

PRODUCING 

SOUTHEAST, INC.

AL 1311 211111 NATURAL GAS 

SWEETNING, 

DEHYRATION

50.002 160 MMSCF/D SULFUR RECOVERY FOLLOWED BY THERMAL OXIDIZATION. THROUGHPUT ALSO 

INCLUDES 280 TON 


SULFUR/DAY

Volatile Organic Compounds 

(VOC)

P THERMAL OXIDIZER AND HIGH TEMPERATURE 3.3 LB/H 98 Y

AL-0175 MOBIL OIL 

EXPLORATION & 

PRODUCING 

SOUTHEAST, INC.

AL 1311 211111 SULFUR RECOVERY 

UNIT

50.002 Volatile Organic Compounds 

(VOC)

P HIGH THERMAL OXIDIZER TEMPERATURE 5.8 LB/H 0 Y

AL-0176 MOBIL OIL 

EXPLORATION & 

PRODUCING 

SOUTHEAST, INC.

AL 1311 211111 STORAGE VESSELS 

& LOADING 

RACK

50.999 CONDENSATES ARE STORED Volatile Organic Compounds 

(VOC)

A VAPOR RECOVERY 95 % 

CAPTURE

95 Y

AL-0183 GULFSTREAM 

COMPRESSOR 

STATION 100

AL 4922 486210 37,896 HP ROLLS 

ROYCE COBERRA 

6562 DLE NG FIRED 

TU

19.8 See facility notes. Volatile Organic Compounds 

(VOC)

P COMBUSTION 

CONTROLS - GOOD 

MIXING OF FUEL AND 




COMBUSTION AIR.

7.2 PPM 0

AL-0189 GALLION 

COMPRESSOR 

STATION

AL 4922 486210 4000 HP DRESSENRAND TLVA-10 2-CY. 

LEAN BU. NG ENG

17.13 4000 HP Volatile Organic Compounds 

(VOC)

N 1.52 G/HP-H 0

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR G3616 

4,735 HP ENGINES 

(3) SN-01 THROUGH 

SN-03

17.1 4735 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY AND OXIDATION CATALYST Formaldehyde P OXIDATION CATALYST 1.05 LB/H 75 N

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR G3616 

4,735 HP ENGINES 

(3) SN-01 THROUGH 

SN-03

17.1 4735 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY AND OXIDATION CATALYST Volatile Organic Compounds 

(VOC)

P OXIDATION 

CATALYST


MIRATECHSP-PTCIT72S3624X41-2X18/30-

H3

0.19 G/HP-H 70 N

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR 

G16CM34 8,180 HP 

ENGINES, SN-04 

THOUGH SN-07

17.1 8180 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY AND OXIDATION CATALYST Formaldehyde P OXIDATION 

CATALYST


MIRATECH SP-RESIGA90S3624X61-42-H4

0.63 LB/H 75 N

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR 

G16CM34 8,180 HP 

ENGINES, SN-04 

THOUGH SN-07

17.1 8180 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY AND OXIDATION CATALYST Volatile Organic Compounds 

(VOC)

P OXIDATION 

CATALYST


MIRATECH SP-RESIGA90S3624X61-42-H4

0.12 G/HP-H 60 N

Attachment 1, page 2 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR 

G16CM34 8,180 HP 

ENGINES, SN-08 

THOUGH SN-10

17.1 8180 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY, OXIDATION CATALYST, AND SCR Formaldehyde P OXIDATION 

CATALYST


MIRATECH SP-RESIGA90S3624X61-42-H4

0.63 LB/H 75 N

AR-0113 RUSSELL 

COMPRESSOR 

STATION

AR 4922 486210 CATERPILLAR 

G16CM34 8,180 HP 

ENGINES, SN-08 

THOUGH SN-10

17.1 8180 HP LEAN BURN ENGINES EQUIPPED WITH LEC TECHNLOGY, OXIDATION CATALYST, AND SCR Volatile Organic Compounds 

(VOC)

P OXIDATION 

CATALYST


MIRATECH SP-RESIGA90S3624X61-42-H4

0.12 G/HP-H 60 N

CA-0528 TEXACO 

EXPLORATION & 

PRODUCTION INC.

CA 1311 211111 COMPRESSOR, GAS 17.22 15 HP OUTPUT Volatile Organic Compounds 

(VOC)

A CRANKCASE BREATHER 0 0

CA-0655 SOUTHERN 

CALIFORNIA GAS 

COMPANY

CA 4923 221210 EMERGENCY IC 

ENGINE DRIVING A 

GENERATOR

17.23 132 HP Volatile Organic Compounds 

(VOC)

A TWO-WAY CATALYST 0 0

CA-0754 MOBIL 

EXPLORATION & 

PRODUCING U.S., 

INC.

CA 1311 211111 LEAN BURN 

NATURAL GAS-FIRED 

IC ENGINE

17.23 280 BHP BACT REQUIRED FOR NEW LEAN-BURN IC ENGINE TO SERVE PRESSURE MAINTENANCE OPERATION FOR STIMULATION OF PRIMARY PRODUCTION WELLS Volatile Organic Compounds 

(VOC)

P AIR/FUEL RATIO CONTROLLER AND CLEANBURN COMBUSTIONTECHNOLOGY WITH WEE1.5 G/B-HP-H 0

CA-0829 G.E.N.Y. 

OPERATIONS 

COMPANY

CA 1311 211111 IC ENGINE, NAT GAS 

FIRED, CATERPILLAR 

MODEL 333

17.23 145 BHP ARB RECORD # A330-828-98 Volatile Organic Compounds 

(VOC)

P POSITIVE CRANKCASE VENTILATION2 G/B-HP-H 0

CA-0858 BEAR MOUNTAIN 

LIMITED

CA 1311 211111 TURBINE, GE, 

COGENERATION, 48 

MW

15.21 48 MW ARB RECORD #: A330-862-98 48 MW GET COGENERATION SYSTEM Volatile Organic Compounds 

(VOC)

A OXIDATION CATALYST 0.6 PPMVD @ 

15% O2

0

CA-1163 BREITBURN ENERGY - 

DOME AND 

NEWLOVE LEASE, 

ORCUTT HILL FIELD

CA 1311 211111 STEAM GENERATOR: 

OIL FIELD 5 TO < 

33.5 MMBTU/HR

13.31 23 23.00 MMBTU/HEQUIP: ULTRA LOW NOX DESIGN AND FLUE GAS RECIRCULATION (FGR)., MFR: NORTH AMERICAN BURNER, TYPE: STEAM GENERATOR, MODEL: 4211-21-LE ULTRA LOW NOX W/FGR, FUNC EQUIP: A STEAM ENHANCED OIL RVolatile Organic Compounds 

(VOC)

A LOW-NOX BURNER AND FGR (VOC AS ROC) 8.5 PPMV @ 

3% O2

0 U

CA-1165 BREITBURN ENERGY - 

NEWLOVE LEASE, 

ORCUTT HILL FIELD

CA 1311 211111 STEAM GENERATOR: 

OIL FIELD >= 50 

MMBTU/HR

13.29 62.5 62.50 MMBTU/HEQUIP: ULTRA LOW NOX DESIGN AND FLUE GAS RECIRCULATION (FGR)., MFR: NORTH AMERICAN BURNER, TYPE: STEAM GENERATOR, MODEL: 4211-24G-LE ULTRA LOW NOX, FUNC EQUIP: A STEAM ENHANCED OIL RECOVVolatile Organic Compounds 

(VOC)

A LOW-NOX BURNER AND FGR (VOC AS ROC) 8.5 PPMV @ 

3% O2

0 U

CA-1169 BREITBURN ENERGYNEWLOVE LEASECA 1311 211111 ULTRA LOW NOX 

BURNER

50.008 50 MMBTU/H BURN EXCESS PRODUCED GAS AT AN OILFIELD.





THE VESSEL WAS CONSTRUCTED BY ENERGY & ENVIRONMENT, INC. AND THE BURNER 

WAS MANUFACTURED BY AMERICAN COMBUSTION TECHNOLOGIES, INC. THE FLARE 

HAS NOT BEEN SOURCE TESTED YET. EMISSIONS ARE BASED ON THE BURNER 

MANUFACTURER'S GAURANTEE OF 12 PPMV NOX, 3 PPMV ROC AND 50 PPMV CO, ALL 

AT 3% O2.

Volatile Organic Compounds 

(VOC)

P FORCED DRAFT ENCLOSED FLARE 0.0013 LB/MMBT

U

0 U

CA-1171 BREITBURN ENERGYNEWLOVE LEASECA 1311 211111 Horizontal Enclosed 

Flare

19.39 50 MMBTU/H Volatile Organic Compounds 

(VOC)

P Forced draft enclosed flare 0.0013 LB/MMBT

U

0 U

CA-1179 VENOCO- ELLWOOD 

ONSHORE FACLITY

CA 1311 211111 Enclosed Thermal 

Oxidizer

11.31 35000 MMBtu Combusted high CO2 natural gas and lo-cat oxidation air Volatile Organic Compounds 

(VOC)

P Burner design, forced air blower, temperature controller 0.0027 LB/MMBT

U

0 U

CO-0021 NORTHWEST 

PIPELINE 

CORPORATION

CO 4923 221210 BURNERS, DUCT, 

COEN

13.31 29 MMBTU/HR PER BURNER Volatile Organic Compounds 

(VOC)

N 1.6 LB/HR 0

CO-0022 SNYDER OIL CORP. / 

ENTERPRISE 

STATION

CO 4922 486210 ENGINES, 

RECIPROCATING (6)

17.13 2500 HP EACH Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION & FUEL SPEC: FIRING RESIDUE QUALITY NAT. GAS 141.3 LBS/MILLIO

N SCF

0

CO-0058 CHEYENNE STATION CO 4922 486210 FREP ENGINE 17.13 13 MMBTU/H CATERPILLAR G3606LE, RATED AT 1775 HP. THE ENGINE IS INCLUDED IN PERMIT 03WE0184. Volatile Organic Compounds 

(VOC)

A OXIDATION CATALYST 0.3 G/B-HP-H 70 U

CO-0058 CHEYENNE STATION CO 4922 486210 CPP ENGINE 17.13 16.47 MMBTU/H CATERPILLAR G3608, RATED AT 2,443 HP. THIS ENGINE IS PERMITTED UNDER 03WE0912.Volatile Organic Compounds 

(VOC)

A OXIDATION CATATLYST 0.3 G/B-HP-H 0 U

CO-0058 CHEYENNE STATION CO 4922 486210 FREP TURBINE 16.11 58 MMBTU/H SOLAR TAURUS MODEL NO. 60-7800S, 6,536 HP. THIS TURBINE IS ADDRESSED ON PERMIT 03WE0185. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES (SEE NOTES) 3 PPMVD 0 U

CO-0058 CHEYENNE STATION CO 4922 486210 CPP TURBINES 16.11 71.42 MMBTU/H TWO SOLAR TAURUS MODEL NO. 70-10302S TURBINES, 9816 HP. THESE TURBINES ARE INCLUDED IN PERMIT 03WE0910. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES (SEE NOTES) 3 PPM @ 

15% O2

0 U

CO-0058 CHEYENNE STATION CO 4922 486210 HEATERS 13.31 45 MMBTU/H TWO HOT OIL HEATERS RATED AT 45 MMBTU/HR AND ONE UTILITY HEATER RATED AT 16 MMBTU/HR. THE HEATERS ARE INCLUDED IN PERMIT 03WE0913. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES0.016 LB/MMBT

U

0 U

CO-0058 CHEYENNE STATION CO 4922 486210 CO2 PLANT 50.999 300 MMSCF/DAY CO2 PLANT CONSISTS OF AN AMINE TREATMENT SKID AND A GLYSOL (TEG) DEHYDRATOR, RATED AT 300 MMSCF/DAY. THE CO2 PLANT IS ADDRESS IN PERMIT 03WE0916. Volatile Organic Compounds 

(VOC)

A FLASH TANK EMISSIONS FROM THE AMINE UNIT AND GLYCOL DEHYRDRATOR AND THE 0 98 U

CO-0059 CHEYENNE STATION CO 4922 486210 PHASE II TURBINE 16.11 71.42 MMBTU/H SOLAR TAURUS, MODEL NO. 70-10302S, RATED AT 9,816 HP. THIS TURBINE IS ADDRESSED IN PERMIT 04WE1390. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES 3 PPM @ 

15% O2

0 U

Attachment 1, page 3 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

CT-0151 KLEEN ENERGY 

SYSTEMS, LLC

CT 4911 221210 SIEMENS SGT6-

5000F COMBUSTION 

TURBINE #1 AND #2 

(NATURAL GAS 

FIRED) WITH 445 

MMBTU/HR 

NATURAL GAS DUCT 

BURNER

15.21 2.1 MMCF/H THROUGHPUT IS FOR TURBINE ONLY WHEN FIRING NATURAL GAS





TURBINE: 2136 MMBTU/HR (2.095 MMCF/HR)


DUCT BURNER: 445 MMBTU/HR (0.436 MMCF/HR)





EMISSION RATES ARE FOR EACH COMBUSTION TURBINE FIRING NATURAL GAS, NOT 

COMBINED.

Volatile Organic Compounds 

(VOC)

N SOME REDUCTIONS OF VOC ARE GAINED FROM CO CATALYST BUT ARE NOT GUARANTE10 LB/H 0

CT-0151 KLEEN ENERGY 

SYSTEMS, LLC

CT 4911 221210 SIEMENS SGT6-

5000F COMBUSTION 

TURBINE #1 AND #2 

(OIL FIRED) WITH 

445 MMBTU/HR 

NATURAL GAS DUCT 

BURNER

15.29 15119 GAL/H THROUGHPUT ABOVE IS FOR TURBINE ONLY WHEN BURNING OIL





TURBINE: 2117 MMBTU/HR (15119 GAL/HR)


DUCT BURNER (NG ONLY): 445 MMBTU (.436 MMCF/HR)





EMISSION RATES ARE FOR EACH COMBUSTION TURBINE TRAIN FIRING OIL, NOT 

COMBINED.

Volatile Organic Compounds 

(VOC)

N SOME VOC REDUCTIONS ARE ACHIEVED THROUGH CO CATALYST BUT ARE NOT GUARAN9 LB/H 0

FL-0074 FLORIDA GAS 

TRANSMISSION

FL 4922 486210 TURBINE, GAS 15.11 131.59 MMBTU/H Volatile Organic Compounds 

(VOC)

N 0.67 LB/H 0

FL-0075 FLORIDA GAS 

TRANSMISSION

FL 4922 486210 ENGINE, 

RECIPROCATING, 

GAS

17.13 4000 BHP/H Volatile Organic Compounds 

(VOC)

N 1.7 G/B-HP-H 0

GA-0104 THOMASTON 

COMPRESSOR 

STATION

GA 4922 486210 COMPRESSOR 

ENGINE, (2)

17.13 4730 HP ENGINES ARE CATERPILLAR G3616 4-STROKE LEAN BURN Volatile Organic Compounds 

(VOC)

A OXIDATION CATALYST 3.13 LB/H 0 U

GA-0104 THOMASTON 

COMPRESSOR 

STATION

GA 4922 486210 COMPRESSOR 

ENGINE, (2)

17.13 4730 HP ENGINES ARE CATERPILLAR G3616 4-STROKE LEAN BURN Formaldehyde A OXIDATION CATALYST 1.13 LB/H 0 U

IA-0056 NATURAL GAS 

PIPELINE COMPANY

IA 4922 486210 COMPRESSOR 

ENGINE

17.13 5500 HP Volatile Organic Compounds 

(VOC)

P NORMAL OPERATION 1.5 G/B-HP-H 0 U

ID-0011 COMPRESSOR 

STATION NO. 4

ID 4922 486210 19500-HP GAS 

TURBINE

16.11 19500 HP THE MAXIMUM THROUGHPUT SHALL NOT EXCEED 1.251 BILLION SCF 


PER ANY CONSECUTIVE 12-MO PERIOD.


EMISSIONS FROM UNIT A ARE CONTROLLED BY DRY LOW-NOX 


COMBUSTION. THIS IS CONSIDERED TO BE BACT FOR GAS 


TURBINES IN NATURAL GAS PIPELINE COMPRESSOR SERVICE.

Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.31 LB/MMSCF 0

IL-0083 PANHANDLE 

EASTERN PIPELINE 

COMPANY

IL 4922 486210 COMPRESSOR 

ENGINES (1118, 

1119)

17.13 2070 HP Through put for each. BACT for CO, NOx, and VOC. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE 0.43 G/B-HP-H 64

IL-0083 PANHANDLE 

EASTERN PIPELINE 

COMPANY

IL 4922 486210 COMPRESSOR 

ENGINES (1116, 

1117)

17.13 4000 HP Throughput for each. BACT for CO, NOx, VOC Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE 0.43 G/B-HP-H 0

IL-0108 STATION 110, 

GENESEO

IL 4922 486210 RECIPROCATING 

ENGINES (5)

17.1 Volatile Organic Compounds 

(VOC)

B USE OF LOW EMISSION COMBUSTION TECHNOLOGY FOR NOX FOR EXISTING ENGINES W0.8 G/B-HP-H 0 U

LA-0077 FLORIDA GAS 

TRANSMISSION 

COMPANY

LA 4922 486210 ENGINE, RECIP, 

NATURAL GAS 

COMPRESSOR

17.13 2400 HP Volatile Organic Compounds 

(VOC)

N 23 T/YR 0

LA-0082 TEXACO INC. - 

ONSHORE DIVISION

LA 1311 211111 COMPRESSORS, 

RECIPROCATING (3)

17.13 1642 HP EACH Volatile Organic Compounds 

(VOC)

P LEAN BURN ENGINE 0 0

LA-0141 DUKE ENERGY FIELD 

SERVICES - MINDEN

LA 1321 211112 Y-GRADE TRUCK 

LOADING AND 

UNLOADING

50.002 22 MM GAL/YR EMISSION POINT 16-81D Volatile Organic Compounds 

(VOC)

N 3.65 LB/H 0

LA-0141 DUKE ENERGY FIELD 

SERVICES - MINDEN

LA 1321 211112 FLARE 19.39 EMISSION POINT 20-81 Volatile Organic Compounds 

(VOC)

N 2.82 LB/H 0

Attachment 1, page 4 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

LA-0141 DUKE ENERGY FIELD 

SERVICES - MINDEN

LA 1321 211112 WAUKESHA 

COMPRESSOR 

ENGINE

17.13 1478 HP EMISSION POINT 3-91 Volatile Organic Compounds 

(VOC)

N 1.63 LB/H 0

LA-0141 DUKE ENERGY FIELD 

SERVICES - MINDEN

LA 1321 211112 AMINE VENT 50.002 EMISSION POINT 1-98 Volatile Organic Compounds 

(VOC)

N 3.68 LB/H 0

LA-0154 MINDEN GAS PLANT LA 4925 221210 COMPRESSOR 

ENGINE, EMISSION 

PT. 01-01

17.13 930 HP Volatile Organic Compounds 

(VOC)

B NON-SELECTIVE 

CATALYTIC 

REDUCTION AND AIRTO-


FUEL RATIO 

CONTROLLER

8.98 T/YR 0

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 FIREWATER PUMP 

DIESEL ENGINES 1-3

17.11 660 HP EACH Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES0.07 LB/H 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 STANDBY 

GENERATOR DIESEL 

ENGINES 1-2

17.11 2220 HP EACH Volatile Organic Compounds 

(VOC)

P COMPLYING WITH 40 CFR 60 SUBPART IIII 0 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 30 MW GAS 

TURBINE 

GENERATORS (4)

15.21 290 MMBTU/H EACH TURBINES EQUIPPED WITH WASTE HEAT RECOVERY UNITS Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES AND THE USE OF NATURAL GAS AS FUEL 1.2 LB/H 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 SUBMERGED 

COMBUSTION 

VAPORIZERS (24)

12.31 108 MMBTU/H Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES AND THE USE OF NATURAL GAS AS FUEL 0.32 LB/H 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 FUGITIVE EMISSIONS 99.999 FUGITIVE EMISSIONS FROM VALVES, CONNECTORS, ETC. Volatile Organic Compounds 

(VOC)

N COMPLY WITH LAC 33:III.2111 0.25 LB/H 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 FUGITIVE EMISSIONS 

(ASSOCIATED W/ 

528 AMBIENT AIR 

VAPORIZERS)

99.999 Volatile Organic Compounds 

(VOC)

N 0.25 LB/H 0 U

LA-0194 SABINE PASS LNG 

TERMINAL

LA 4922 486210 FIREWATER 

BOOSTER PUMP 

DIESEL ENGINES (2)

17.21 300 HP EACH OPERATING TIME = 500 H/YR. Volatile Organic Compounds 

(VOC)

P GOOD ENGINE DESIGN & PROPER OPERATING PRACTICES 0.1 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 FIREWATER PUMP 

DIESEL ENGINE

17.11 660 HP Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES AND GOOD ENGINE DESIGN 0.04 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 FIREWATER PUMP 

DIESEL ENGINE

17.11 525 HP Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES AND GOOD ENGINE DESIGN 0.09 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 DIESEL EMERGENCY 

GENERATOR NOS. 1 

& 2

17.11 2168 HP EACH Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES AND GOOD ENGINE DESIGN 1.67 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 GAS TURBINE 

GENERATOR NOS. 1-

4

15.11 30 MW EA. 290 MM BTU/HR EA. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES1.21 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 SUBMERGED 

COMBUSTION 

VAPORIZER NOS. 1-

21

19.9 108 MMBTU/H EA. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES0.32 LB/H 0 U

LA-0219 CREOLE TRAIL LNG 

IMPORT TERMINAL

LA 4922 486210 FUGITIVE EMISSIONS 99.999 Volatile Organic Compounds 

(VOC)

N 0.62 LB/H 0 U

Attachment 1, page 5 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 COMPRESSOR 

TURBINE NO. 1

16.11 79.1 MMBTU/H TURBINE DRIVES 10,311 HP COMPRESSOR Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES INCLUDING THE USE OF CLEAN BURNING FUELS SUCH 2.62 LB/H 0 U

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 COMPRESSOR 

TURBINE NO. 2

16.11 79.1 MMBTU/H TURBINE DRIVES 10,311 HP COMPRESSOR Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES INCLUDING THE USE OF CLEAN BURNING FUELS SUCH 2.62 LB/H 0 U

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 COMPRESSOR 

ENGINE NO. 1

17.13 32.2 MMBTU/H 4,735 HORSEPOWER COMPRESSOR Volatile Organic Compounds 

(VOC)

B CATALYTIC OXIDATION AND GOOD COMBUSTION PRACTICES 1.84 LB/H 0 U

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 EMERGENCY 

BACKUP GENERATOR

17.13 838 HP Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES INCLUDING THE USE OF CLEAN BURNING FUELS SUCH 1.39 LB/H 0 U

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 CONDENSATE 

STORAGE TANK

42.005 5760 BBL/YR 100 BBL VOLUME Volatile Organic Compounds 

(VOC)

P SUBMERGED FILL PIPE 1.28 LB/H 0 U

LA-0232 STERLINGTON 

COMPRESSOR 

STATION

LA 4922 486210 TRUCK LOADING OF 

CONDENSATE

42.999 5760 BBL/YR CONDENSATE Volatile Organic Compounds 

(VOC)

P SUBMERGED LOADING AND DEDICATED SERVICE 26.1 LB/H 0 U

MI-0269 ANR PIPELINE 

CO./BRIDGMAN 

COMPRESSOR 

STATION

MI 4922 486210 COMBUSTION 

TURBINE, 15000 HP 

SOLAR MARS

16.11 13803 HP EQUIVALENT TO APPROXIMATELY 10.3 MW. 114 KJ/H, 108 MMBTU/H Volatile Organic Compounds 

(VOC)

P FUEL USE LIMIT. STAGED COMBUSTION. HOURLY EMISSION RATE CONVERTS TO 39 T/Y8.9 LB/H 0 Y

MI-0305 CONSUMERS 

ENERGY 

(MUSKEGON RIVER 

COMPRESSOR)

MI 4925 486210 GLYCOL 

DEHYDRATOR, 

TRIETHYLENE

50.999 260 MMSCF/DAY VOC DESTRUCTION EFFICIENCY MUST BE TESTED TO ASSURE 98%. 


THE APPLICABLE MACT IS 40 CFR 63.1274 (D) (2). GLYCOL 


RATE 15-30 GPM.

Benzene A THERMAL OXIDIZER. 

DESIGNED FOR 1400 

DEGREES F 


AND 0.5 SECOND 

RESIDENCE. THE 

THERMAL OXIDIZER 


IS NEW.

0.8 T/YR 98

MI-0323 KCS MICHIGAN 

RESOURCES 

(MAYFIELD 28)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.009 2.4 MMSCF/D GLYCOL RECIRCULATION RATE MAXIMUM 0.28 GPM. Benzene A CONDENSER 0.27 T/YR 0

MI-0323 KCS MICHIGAN 

RESOURCES 

(MAYFIELD 28)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.009 2.4 MMSCF/D GLYCOL RECIRCULATION RATE MAXIMUM 0.28 GPM. Volatile Organic Compounds 

(VOC)

A FLASH TANK ADDED. 

DOWNCOMER 

CONDENSER EXHAUST 




TEMPERATURE 

MAINTAINED AT 100 

DEGREES F OR LESS.

3.7 T/YR 0

MI-0324 SAVOY ENERGY 

(TOWER)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 300000 CF/D REBOILER STILL STACK Volatile Organic Compounds 

(VOC)

P PRODUCTION IS 

LIMITED TO 300000 

CF/DAY, 12-MONTH 


ROLLING TIME PERIOD

13.5 T/YR 0

MI-0324 SAVOY ENERGY 

(TOWER)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 300000 CF/D REBOILER STILL STACK Benzene N N/A 0.22 T/YR 0

MI-0325 MICHIGAN 

CONSOLIDATED GAS 

(BELLE RIVER MILLS)

MI 4923 211111 GLYCOL 

DEHYDRATOR

50.999 986 MMSCF/D CONSISTS OF TWO TOWERS, TWO 15 GPM CIRCULATION PUMPS Benzene A ENCLOSED FLARE CONTROL OF STILL OFF GAS. 0.43 T/YR 99

MI-0325 MICHIGAN 

CONSOLIDATED GAS 

(BELLE RIVER MILLS)

MI 4923 211111 GLYCOL 

DEHYDRATOR

50.999 986 MMSCF/D CONSISTS OF TWO TOWERS, TWO 15 GPM CIRCULATION PUMPS Volatile Organic Compounds 

(VOC)

A ENCLOSED FLARE 

CONTROL OF STILL OFFGAS. EXCEEDS 


REQUIREMENT OF 

MACT, 40 CFR 63.1274 

(D)(2)

9 T/YR 99

MI-0330 SAVOY ENERGY 

(OTSEGO LAKE)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 350000 CF/D REBOILER STILL STACK Benzene N NA 0.49 T/YR 0

Attachment 1, page 6 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

MI-0330 SAVOY ENERGY 

(OTSEGO LAKE)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 350000 CF/D REBOILER STILL STACK Volatile Organic Compounds 

(VOC)

P PRODUCTION IS 

LIMITED TO 350000 

CF/DAY, 12-MONTH 


ROLLING TIME 

PERIOD. HAPS ARE 

ALSO LIMITED TO 


MINOR SOURCE 

STATUS. 

DOWNCOMER 

CONDENSER 


TEMPERATURE MUST 

BE 105 DEGREES F OR 

LESS.

12.6 T/YR 0

MI-0332 SAVOY ENERGY 

(FREDERIC TWP)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 600000 CF/D 100000 BTU REBOILER Volatile Organic Compounds 

(VOC)

P PRODUCTION IS 

LIMITED TO 600000 

CF/DAY; 12-MONTH 


ROLLING AVERAGE. 

HAPS ARE ALSO 

LIMITED TO MINOR 


SOURCE STATUS. 

ABOUT ONE-HALF VOC 

FROM STILL, 


ONE-HALF FROM GASDRIVEN GLYCOL 

PUMP.

13.9 T/YR 0

MI-0332 SAVOY ENERGY 

(FREDERIC TWP)

MI 1311 211111 GLYCOL 

DEHYDRATOR

50.999 600000 CF/D 100000 BTU REBOILER Benzene N NA 0.22 T/YR 0

MI-0341 ANR PIPELINE 

COMPANY - REED 

CITY

MI 4923 486210 GLYCOL 

REGENERATION, 

REBOILER STILL VENT

50.002 120 SCFM regeneration of glycol solution. Benzene A THERMAL OXIDIZER, CONDENSER BACKUP. 1 T/YR 95

MI-0341 ANR PIPELINE 

COMPANY - REED 

CITY

MI 4923 486210 GLYCOL 

REGENERATION, 

REBOILER STILL VENT

50.002 120 SCFM regeneration of glycol solution. Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZER, CONDENSER BACKUP. 90 LB/D 95

MI-0342 CONSUMERS 

ENERGY COMPANY - 

RAY STATION

MI 4925 486210 GLYCOL 

REGENERATION (2)

50.002 600 MMSCF/D Throughput is natural gas throughput. Circulation rate for 


each unit is 19.1 gpm. Reboiler fuel rate 1.4 mmbtu/h, 


each.

Volatile Organic Compounds 

(VOC)

A THERMAL OXIDATION IN THE REBOILER BURNER. 71 LB/D 92

MS-0021 ENRON GAS 

PIPELINE OPERATING 

CO.

MS 4922 486210 ENGINE, 412 KVSR 

DRESSER

17.13 2400 HP Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 1.33 G/B-HP-H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2511E, 

COOPER GMVA-6

17.13 750 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 1.65 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2512E, 

CLIMAX V-125

17.23 320 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 0.7 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2514E, 

INGERSOLL RAND 

SVG-12

17.13 660 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 1.45 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2515E, 

WAUKESHA L3711

17.23 285 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 0.63 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2516E, 

WAUKESHA L3711

17.23 285 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 0.63 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 TURBINE, 2551E, 

SOLAR SATURN

16.11 1100 HP EMERGENCY GENERATOR, LIMIT OF 500 HOURS OF OPERATION PER YEAR. EMISSION LIMITS IN STANDARDIZED UNITS NOT AVAILABLE. Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS. 3.15 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 2-CYCLE LEAN BURN 

ENGINE, UNIT 2505E

17.13 1000 HP ALL CONTROLLED BY 2ND GENERATION CLEAN BURN CONTROLS. Volatile Organic Compounds 

(VOC)

P 2ND GENERATION CLEAN BURN CONTROL 2.2 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2506E 17.13 2200 HP 2ND GENERATION LEAN BURN TECH CONTROLS FOR ALL POLLUTANTS. Volatile Organic Compounds 

(VOC)

P 2ND GENERATION CLEAN BURN CONTROLS 4.84 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 TURBINE, 2507E, 

SOLAR T-1001

16.11 1100 HP EMISSIONS IN STANDARDIZED UNITS NOT AVAILABLE. Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 3.15 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 TURBINE, 2508E, 

SOLAR CENTAR

16.11 4756 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS. 1.05 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2503E, 

COOPER GMVA-10

17.13 1265 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 2.78 LB/H 0

Attachment 1, page 7 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, 2504E, 

COOPER GMVA-6

17.13 750 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN CONTROLS 1.65 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, CLEAN 

BURN, 2517E 

COOPER GMVH-8

17.13 2000 HP 2ND GENERATION CLEAN BURN TECHNOLOGY IS CONTROL FOR ALL POLLUTANTS. Volatile Organic Compounds 

(VOC)

P 2ND GENERATION CLEAN BURN CONTROLS 4.4 LB/H 0

NE-0015 KN ENERGY. INC NE 4922 486210 IC ENGINE, (2), 

2501E & 2502E 

CLARK RA-6

17.13 565 HP THROUGHPUT FOR EACH Volatile Organic Compounds 

(VOC)

P 2ND GENERATION CLEAN BURN CONTROLS 1.24 LB/H 0

NJ-0029 ALGONQUIN'S 

HANOVER 

COMPRESSOR 

STATION

NJ 4922 486210 TURBINES 

COMBUSTION, (2) 

TWO SOLAR 

CENTAUR

16.11 3.1 MW EACH TURBINES AS NATURAL GAS COMPRESSOR DRIVES; 41 MMBTU/H. ONLY 


NATURAL GAS SHALL BE BURNED IN THE TURBINE. *TWO PERMITS 


WERE FOUND FOR THIS FACILITY - ONE RACT PERMIT THAT ONLY 


LISTED NOX, AND A PSD PERMIT THAT LISTED ALL OTHER 


POLLUTANTS INCLUDING DIFFERENT LIMITS FOR NOX.

Volatile Organic Compounds 

(VOC)

N 0.21 LB/H 0

NJ-0052 DQE NJ 4925 221210 SOLAR TARUS GAS 

TURBINE

16.15 70.8 MMBTU/H, 6.2 MWSULFUR <= 0.8% BY WEIGHT IN FUEL Volatile Organic Compounds 

(VOC)

N 1.01 LB/H 0 Y

NJ-0053 MCUA NJ 4925 221210 DUCT FIRED HRSG 13.39 31 MMBTU/H NOMINAL * *43 MMBTU/HR PEAK THROUGHPUT CAPACITY/SIZE Volatile Organic Compounds 

(VOC)

N 1.62 LB/H 0 U

NJ-0053 MCUA NJ 4925 221210 TURBINE WITH HRSG 16.25 74 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE 4.39 LB/H 0 U

NJ-0053 MCUA NJ 4925 221210 OPEN FLARE 19.32 90 MMBTU/H* *@ 500BTU/SET OF HHV, FEED RATE = 3000 SCFM


-<= 3000 SCFM ON 1-HR BLOCK BASIS, SERVE AS BACK-UP TO 


TURBINES

Volatile Organic Compounds 

(VOC)

N NONE 2.5 LB/H 0

NJ-0053 MCUA NJ 4925 221210 OPEN FLARE 19.32 90 MMBTU/H* *@ 500BTU/SET OF HHV, FEED RATE = 3000 SCFM


-<= 3000 SCFM ON 1-HR BLOCK BASIS, SERVE AS BACK-UP TO 


TURBINES

Volatile Organic Compounds 

(VOC)

N NONE- FLARE EFFICIENCY 3.4 LB/H 98 U

NJ-0053 MCUA NJ 4925 221210 LANDFILL GAS 

TURBINE

16.15 65 MMBTU/H (NOMINAL)* *74MMBTU/HR PEAK THROUGHPUT CAPACITY/SIZE Volatile Organic Compounds 

(VOC)

N NONE 2.78 LB/H 0 U

NJ-0055 ALGONQUIN GAS NJ 4922 486210 2 SOLAR TAURUS 

SIMPLE CYCLE 

STATIONARY 

TURBINE

16.11 67.84 MMBTU/H, 7520 BHP NATURAL GAS USAGE <= 325.064 MM CU FT/YR PER GAS TURBINE. 


NATURAL GAS TOTALIZING FLOW METER WILL BE INSTALLED IN 


TURBINES

Volatile Organic Compounds 

(VOC)

N N/A 0.21 LB/H 0 Y

NM-0021 WILLIAMS FIELD 

SERVICES CO. - EL 

CEDRO 

COMPRESSOR

NM 4922 486210 ENGINE, GAS-FIRED, 

RECIPROCATING

17.13 1000 HP Volatile Organic Compounds 

(VOC)

P CLEAN/LEAN BURN TECHNOLOGY 1 G/B-HP-H 0

NM-0021 WILLIAMS FIELD 

SERVICES CO. - EL 

CEDRO 

COMPRESSOR

NM 4922 486210 TURBINE, GAS-FIRED 16.11 11257 HP Volatile Organic Compounds 

(VOC)

P COMBUSTION CONTROL 25 PPM @ 

15% O2

0

NM-0025 MERIDIAN OIL, INC. - 

FRANCIS MESA STA.

NM 4922 486210 COMPRESSOR 

ENGINES (8) & 

GLYCOL 

DEHYDRATOR

17.13 2650 HP EACH ENGINE MFR: SUPERIOR MODEL #16SGTB - 2650 HP Volatile Organic Compounds 

(VOC)

P COMPRESSOR STATION, CLEAN BURN ENGINES 6.6 G/HP-H 0

NM-0026 MERIDIAN OIL, 

INC./VALVERDE GAS 

PROCESSING FAC.

NM 1311 211111 RECIPROCATING 

ENGINE, NATURAL 

GAS (4)

19.8 0 ADDING FOUR NEW ENGINES Volatile Organic Compounds 

(VOC)

P CLEAN BURN ENGINE MODEL #: 3612 TA/SW66 MANUFACTURER: CA0.8 G/B-HP-H 0

NM-0030 WILLIAMS FIELD 

SERVICES--MIDDLE 

MESA CDP

NM 4922 486210 NATURAL GAS 

COMPRESSOR 

STATION, 14 

ENGINES

17.13 1478 HP EACH WAUKESHA 7042 GL ENGINES Volatile Organic Compounds 

(VOC)

P CLEAN/LEAN BURN TECHNOLOGY 3 LB/HR 

EACH 

ENGINE

0

NM-0032 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 NATURAL GAS 

RECIPROCATING 

ENGINE

17.13 1478 HP COMPLIANCE TO BE VERIFIED AFTER PERMIT REISSUED. COMPLIANCE VERIFICATION WILL BE A PERMIT CONDITION. ENGINE MODEL: WAUKESHA 7042GL Volatile Organic Compounds 

(VOC)

P LEAN BURN DESIGN 1 G/B-HP-H 0

NM-0032 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 GLYCOL 

DEHYDRATORS

50.002 0 Volatile Organic Compounds 

(VOC)

P USE OF COAL SEAM GAS IN THE FACILITY 7.662 T/Y 0

NM-0033 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 DEHYDRATORS, 

GLYCOL

50.002 0 ADDING THREE NEW TEG 20 MMSCFD DEHYDRATORS FOR A TOTAL OF 8 DEHYDRATORS. Volatile Organic Compounds 

(VOC)

P UNITS ARE LIMITED TO LOW VOC COAL SEAM GAS PROCESSING ONLY 5.6 T/YR 0

NM-0033 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 ENGINE, IC 

RECIPROCATING, 

NAT. GAS

17.13 1374 HP CENTRAL DELIVERY POINT FOR COAL SEAM GAS PRODUCTION. Volatile Organic Compounds 

(VOC)

P CLEAN BURN COMBUSTION TECHNOLOGY 1 G/B-HP-H 0

NM-0035 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 RECIPROCATING 

ENGINE, NAT. GAS

17.13 1375 HP CENTRAL DELIVERY POINT FOR COAL SEAM GAS PRODUCTION. Volatile Organic Compounds 

(VOC)

P CLEAN BURN COMBUSTION TECHNOLOGY 1 G/B-HP-H 0

NM-0035 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 GLYCOL 

DEHYDRATORS

50.002 0 Volatile Organic Compounds 

(VOC)

P UNITS ARE LIMITED TO LOW VOC COAL SEAM GAS PROCESSING ONLY 5.6 TPY 0

NM-0036 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 GLYCOL 

DEHYDRATORS

50.002 120 MMSCFD DEHYDRATORS Volatile Organic Compounds 

(VOC)

P LIMITED TO PROCESSING COAL SEAM NATURAL GAS AND EMITTING NO MORE THAN T1.42 LB/H 0

Attachment 1, page 8 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

NM-0036 WILLIAMS FIELD 

SERVICES CO.

NM 4922 486210 RECIPROCATING 

ENGINES, NAT. GAS

17.13 21920 HP DEHYDRATORS (6 NEW 20 MMSCFD UNITS) ARE LIMITED TO PROCESSING COAL SEAM GAS.Volatile Organic Compounds 

(VOC)

P LEAN BURN ENGINE DESIGN 2.65 G/B-HP-H 0

NM-0040 WILLIAMS FIELD 

SERVICES

NM 4922 486210 IC ENGINE, 

COMPRESSOR

17.19 27240 HP FACILITY INCLUDES 6 10MMSCF/D DEHYDRATORS. INSPECTIONS AND COMPLIANCE TESTING WILL OCCUR AND THE PROPOSED SOURCE DEMONSTRATED COMPLIANCE WITH APPLICABLE STANDARDS. Volatile Organic Compounds 

(VOC)

P LEAN-BURN ENGINE DESIGN 1 G/B-HP-H 0

NM-0041 WILLIAMS FIELD 

SERVICES - MIDDLE 

MESA CDP

NM 4922 486210 GENERAL ELECTRIC 

PG7241 (FA) 

COMBUSTION 

ENGINE

17.13 1510 MMBTU/H NATURAL GAS ONLY. EMISSION LIMITS SET FOR VOC, CO AND NOX ONLY Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICES 1 G/B-HP-H 0

NV-0046 GOODSPRINGS 

COMPRESSOR 

STATION

NV 4922 486210 LARGE COMBUSTION 

TURBINE - SIMPLE 

CYCLE

15.11 97.81 MMBTU/H THE THROUGHPUT IS THE FUEL FLOW OF ONE TURBINE OPERATING AT THE FULL LOAD. THERE ARE THREE IDENTICAL TURBINES, EACH IS RATED AT 15,000 HP (11.5 MWE). THEIR MODEL IDENTIFICATION IS MARS 100-T150Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE0.0069 LB/MMBT

U

0 Y

NV-0046 GOODSPRINGS 

COMPRESSOR 

STATION

NV 4922 486210 COMMERCIAL/INSTI

TUTIONAL BOILER

13.31 3.85 MMBTU/H THE UNIT'S MODEL IDENTIFICATION IS PEERLESS 724 FDA WU. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PROCESS0.0052 LB/MMBT

U

0 N

NV-0048 GOODSPRINGS 

COMPRESSOR 

STATION

NV 4922 486210 SIMPLE-CYCLE 

SMALL 

COMBUSTION 

TURBINES (<25 

MW)

16.11 11.5 MW THE FACILITY CONSISTS OF THREE GAS TURBINES OF THE SAME MODEL (SOLAR MARS 100-T15000S) AND THE SAME RATING (15,000 HORSE POWER). EACH TURBINE IS EQUIPPED WITH A SOLONOX BURNER SYSTEM, WHICVolatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE0.0069 LB/MMBT

U

0 U

NV-0048 GOODSPRINGS 

COMPRESSOR 

STATION

NV 4922 486210 COMMERCIAL/INSTI

TUTIONAL-SIZE 

BOILER (<100 

MMBTU/H)

13.31 3.85 MMBTU/H THE PROCESS CONSISTS OF ONE PEERLESS BOILER. THE BOILER IS ALLOWED TO OPERATE 8,760 HOURS PER YEAR. Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE0.005 LB/MMBT

U

0 U

NV-0048 GOODSPRINGS 

COMPRESSOR 

STATION

NV 4922 486210 LARGE INTERNAL 

COMBUSTION 

ENGINE (>500 HP)

17.23 5.91 MMBTU/H THE PROCESS CONSISTS OF ONE WAUKESHA GAS-FIRED GENERATOR FOR EMERGENCY USE. THE GENERATOR IS RATED AT 575 KW OR 771 HP. ROUTINE MAINTENANCE CALLS FOR FIRING UP THE GENERATOR ONCE PER WEVolatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE 0.23 G/B-HP-H 0 U

NY-0091 ALGONQUIN GAS NY 4922 486210 CLARK TLA-8 

RECIPROCATING 

ENGINES (4)

17.13 18.9 MMBTU/H SEE FACILITY NOTES. ADDITIONAL THROUGHPUT: 2500 HP-H. 


EMISSION POINT NUMBERS R0200, R0100, R0300, R0400

Volatile Organic Compounds 

(VOC)

P LIMITED USE 12.9 LB/H 0 Y

OH-0211 CGN TRANSMISSION OH 4922 486210 ENGINES, NATURAL 

GAS COMPRESSOR 

(2)

17.13 4200 HP EACH Volatile Organic Compounds 

(VOC)

P ENGINE TUNING (SEE NOTES) 0.9 G/B-HP-H 0

OH-0211 CGN TRANSMISSION OH 4922 486210 ENGINE, NATURAL 

GAS COMPRESSOR

17.13 3200 HP Volatile Organic Compounds 

(VOC)

P ENGINE TUNING (SEE NOTES) 0.8 G/B-HP-H 0

OH-0212 CGN TRANSMISSION OH 4922 486210 ENGINES, NATURAL 

GAS COMPRESSOR 

(2)

17.13 4200 HP EACH Volatile Organic Compounds 

(VOC)

P ENGINE TUNING (SEE NOTES) 0.98 G/B-HP-H 0

OH-0213 CNG TRANSMISSION 

CORPORATION

OH 4922 486210 ENGINE, NATURAL 

GAS COMPRESSOR

17.13 4200 HP Volatile Organic Compounds 

(VOC)

P ENGINE TUNING (SEE NOTES) 0.9 G/B-HP-H 0

OH-0213 CNG TRANSMISSION 

CORPORATION

OH 4922 486210 ENGINE, NATURAL 

GAS COMPRESSOR

17.13 3200 HP Volatile Organic Compounds 

(VOC)

P ENGINE TUNING (SEE NOTES) 0.8 G/B-HP-H 0

OH-0262 ANR OH 4922 486210 COMPRESSOR 

TURBINES (2), 

SIMPLE CYCLE

15.11 122 MMBTU/H Two natural gas-fired 122 mmBtu/h (36 MW) compressor 


turbines, for natural gas transmission

Volatile Organic Compounds 

(VOC)

P NATURAL GAS ONLY FUEL, GOOD COMBUSTION 8.9 LB/H 0 Y

OH-0262 ANR OH 4922 486210 COMPRESSOR 

TURBINES (2), 

SIMPLE CYCLE

15.11 122 MMBTU/H Two natural gas-fired 122 mmBtu/h (36 MW) compressor 


turbines, for natural gas transmission

Formaldehyde P NATURAL GAS, GOOD COMBUSTION0.1 LB/H 0 Y

OH-0262 ANR OH 4922 486210 EMERGENCY 

GENERATOR

17.23 500 HP 500 hp natural gas fired emergency generator Volatile Organic Compounds 

(VOC)

P NATURAL GAS ONLY FUEL, GOOD COMBUSTION 0.5 LB/H 0 Y

OK-0023 AMOCO RED OAK 

GAS GATHERING 

SYSTEM

OK 4922 486210 ENGINE, I.C., 

COMPRESSOR, 3 EA

17.19 2850 HP Volatile Organic Compounds 

(VOC)

P LEAN BURN ENGINE 9.42 LB/H 50

OK-0024 NGPL OK 4922 486210 ENGINE 17.13 1600 HP Volatile Organic Compounds 

(VOC)

P LEAN BURN COMBUSTION 1 G/B-HP-H 65

OK-0024 NGPL OK 4922 486210 ENGINE 17.13 2400 HP Volatile Organic Compounds 

(VOC)

P LEAN BURN COMBUSTION 1 G/B-HP-H 65

OK-0026 SWIFT ENERGY OK 4922 486210 ENGINES, I.C. 17.13 1132 HP EACH Volatile Organic Compounds 

(VOC)

A CATALYTIC CONVERTER 7.1 T/YR 70

OK-0026 SWIFT ENERGY OK 4922 486210 DEHYDRATION UNIT 50.002 20 MMSCFD Benzene A FLARE 1.3 T/YR 99

OK-0069 STA 102-NG 

PIPELINE OF 

AMERICA

OK 4922 486210 RECIPROCATING 

COMBUSTION 

ENGINE

17.13 6900 HP Volatile Organic Compounds 

(VOC)

P LEAN BURN TECHNOLOGY 2 G/B-HP-H 0

Attachment 1, page 9 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

PA-0043 ELLISBURG 

COMPRESSOR 

STATION

PA 4922 486210 ENGINE, 412 KVE-1, 

DRESSER RAND

17.13 2850 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN TECHNOLOGY 1 G/B-HP-H 0

PA-0063 ELLISBURG 

COMPRESSOR 

STATION

PA 4922 486210 IC ENGINE, (2) 17.13 3000 HP Volatile Organic Compounds 

(VOC)

N 31.2 T/YR 0 U

PA-0077 NATIONAL FUEL GAS 

SUPPLY

PA 4923 221210 IC ENGINES, 

RECIPROCAL, NAT 

GAS, (2)

17.13 1300 HP Throughput for each. COMPLIANCE TESTING REQUIRED FOR NOX,

CO, AND VOC.

Volatile Organic Compounds 

(VOC)

P CLEAN BURN TECHNOLOGY 2.15 LB/H 0

PA-0085 CNG TRANSMISSION 

CORPORATION - 

FINNEFROCK 

STATION

PA 4923 486210 IC ENGINE, 

RECIPROCATING, 2 

CYCLE

17.13 4200 HP Volatile Organic Compounds 

(VOC)

P CLEAN BURN TECHNOLOGY 0.9 G/B-HP-H 0

PA-0155 CNG TRANSMISSION 

CORP., GREENLICK 

STATION

PA 4922 486210 ENGINES, LEAN 

BURN

17.13 3200 G/B-HP-H WHITE LEAN BURN ENGINE (FOUR) MODEL 2416. Volatile Organic Compounds 

(VOC)

A CATALYST MAXIM MODEL 30 1.38 LB/H 50

PA-0230 EASTERN SHORE 

NAT. GAS 

/DALEVILLE

PA 4922 486210 IC COMPRESSOR 

ENGINES

17.13 1665 BHP Volatile Organic Compounds 

(VOC)

N 0.9 G/B-HP-H 0 Y

TX-0258 NATURAL GAS 

COMPRESSION 

FACILITY

TX 1311 211111 (4) INGERSOLL-RAND 

SVG-12 

COMPRESSOR 

ENGINES

17.13 660 HP EACH CM6-9 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.45 LB/H 0

TX-0258 NATURAL GAS 

COMPRESSION 

FACILITY

TX 1311 211111 WAUKESHA L7042G 

COMPRESSOR 

ENGINE

17.13 800 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.76 LB/H 0

TX-0258 NATURAL GAS 

COMPRESSION 

FACILITY

TX 1311 211111 PROCESS 

EQUIPMENT 

FUGITIVES

19.9 PROCESS EQUIPMENT FUGITIVES Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.72 LB/H 0

TX-0286 WARREN 

PETROLEUM 

RESIDUE GAS 

COMPRESSORS

TX 1321 211112 FUGITIVES 50.007 FUGITIVE EMISSIONS ARE AN ESTIMATE ONLY AND SHOULD NOT BE 


CONSIDERED A MAXIMUM ALLOWABLE EMISSION RATE.

Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0286 WARREN 

PETROLEUM 

RESIDUE GAS 

COMPRESSORS

TX 1321 211112 CLARK BA-6 ENGINES 

(5)

17.13 1200 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 2.54 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 GMVH-12 ENGINE 19.8 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 5.29 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) CLARK TLAB-6 

ENGINES

19.8 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 2.2 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) IR-SVG-8 

ENGINES

19.8 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.48 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 HOT OIL HEATER, 

EPN 26

13.31 32.2 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE INDICATED 2.8 LB/MMSCF 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL STILL VENT 50.002 Benzene N NONE INDICATED 0.34 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL STILL VENT 50.002 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 9.42 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 (3) COOPERBESSEMER ENGINES, 

EPN21,-22&-23

17.13 3105 HP THROUGHPUT IS FOR EACH UNIT Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.6 G/B-HP-H 0 U

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 HEATER 19.6 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.09 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 PROCESS/EMERGEN

CY FLARE, EPN29

19.39 PROCESS AND/OR UPSET EMISSIONS MAY BE EMITTED FROM THIS 


EMISSION POINT PROCESS/EMERGENCY FLARE.

Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 FUGITIVES, GLFUG 50.002 Volatile Organic Compounds 

(VOC)

P NSPS SUBPART KKK REQUIREMENTS 9.08 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 PROCESS/EMERGEN

CY FLARE, EPN9

19.39 PROCESS AND/OR UPSET EMISSIONS MAY BE EMITTED FROM THIS 


EMISSION POINT PROCESS/EMERGENCY FLARE.

Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) IR-KVS-8 

ENGINES, EPN10A 

& 10 B

19.8 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.5 LB/H 0

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL REBOILER 50.002 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

Attachment 1, page 10 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

TX-0300 SALT CREEK GAS 

PLANT

TX 1321 211112 FUGITIVES, O2FUG 50.002 Volatile Organic Compounds 

(VOC)

P NSPS SUBPART KKK REQUIREMENTS 9.33 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 (7) TANKS, TANK3-6,-

10,14&15

50.002 (2) CORROSION INHIBITO TANKS (TANK 3 & 4), (3) ENGINE 


COOLANT TANKS (TANK 5, 6 & 14), (2) ENGINE LUBE OIL TANKS 


(TANK 10 & 15)

Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 (2) SELEXOL 

SWEETENER NO 

1&2, SLXOLT01&-T02

50.006 ALL SELEXOL UNIT FLASH GAS STREAMS THAT ARE NOT RECYCLED 


BACK INTO THE PROCESS MUST BE BURNED IN THE THERMAL 


OXIDIZERS.

Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZERS 65.29 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 SELEXOL UNIT 

DEHYDRATOR STILL 

VENT, VENT-DEHY

50.006 ALL SELEXOL UNIT FLASH GAS STREAMS THAT ARE NOT RECYCLED 


BACK INTO THE PROCESS MUST BE BURNED IN THE THERMAL 


OXIDIZERS.

Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZERS 26.46 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 WAUKESHA 7042GSI 

ENGINE, STK-COMP8

19.8 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 FACILITY FUGITIVE 

EMISSIONS, F1

50.002 Volatile Organic Compounds 

(VOC)

P H2S SERVICE LDAR 0.11 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 SELEXOL STORAGE 

TANK, TANK 1

50.002 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 (2) WASTEWATER 

TANKS 1 & 2, 

TANK 11 & 12

50.009 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 SLOP OIL/WATER 

TANK, TANK 13

50.009 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.01 LB/H 0

TX-0312 MITCHELL TREATING 

FACILITY

TX 4922 486210 SELEXOL UNIT 

DEHYDRATOR 

REBOILER, STKRBLR1

50.006 ALL SELEXOL UNIT FLASH GAS STREAMS THAT ARE NOT RECYCLED 


BACK INTO THE PROCESS MUST BE BURNED IN THE THERMAL 


OXIDIZERS.

Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZERS 0.01 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) INGERSOLL-RAND 

ENGINES, #IR-SVG-8, 

EPN4&5

17.23 440 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.48 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 HOT OIL HEATER, 

EPN6

13.31 12 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.08 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) INGERSOLL-RAND 

ENGINES, #IR-SVG-8, 

EPN10A&B

17.13 1330 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.76 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL REBOILER, 

EPN11

13.31 2.5 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.02 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL STILL VENT, 

EPN14

50.005 Benzene N NONE INDICATED 0.34 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 GLYCOL STILL VENT, 

EPN14

50.005 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 9.42 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 (3) COOPERBESSEMER ENGINES, 

#GMVH-12C2, 

EPN21-23

17.13 3105 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 10.94 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 HOT OIL HEATER, 

EPN26

13.31 32.5 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.21 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) FLARES, EPN 9 

& 29

19.33 THIS AMENDMENT IS TO ACCURATELY REPRESENT THAT EITHER 


FLARE 


CAN BE USED AS A PROCESS FLARE AND TO USE 2001 ACTUAL GAS 


FLOWS TO PREDICT THE VOLUME OF GAS PROCESSED. CURRENT GAS 


ANALYSES WERE PROVIDED TO ACCURATELY REPRESENT THE CO2, 


H2S, AND VOC CONTENT OF THE GAS STREAMS.

Volatile Organic Compounds 

(VOC)

N THE FLARE IS A VOC CONTROL42.82 LB/H 98

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 HP TEG FIREBOX, 

EPN30

13.31 3 MMBTU/H Volatile Organic Compounds 

(VOC)

N NONE INDICATED 0.02 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 FUGITIVES, NGLFUG 50.007 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 9.08 LB/H 0

Attachment 1, page 11 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 FUGITIVES, CO2FUG 50.007 Volatile Organic Compounds 

(VOC)

N NONE INDICATED 9.33 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 COOPER-BESSEMER 

ENGINE, #GMVH-12, 

EPN1

17.13 2400 HP Volatile Organic Compounds 

(VOC)

N NONE INDICATED 6.35 LB/H 0

TX-0364 SALT CREEK GAS 

PLANT

TX 1321 211112 (2) CLARK ENGINE, 

#TLAB-6, 

EPN2&3

17.13 2000 HP EACH Volatile Organic Compounds 

(VOC)

N NONE INDICATED 1.32 LB/H 0

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 AUXILIARY BOILER, 

(2)

13.31 6 MMBTU/H BOILERS ARE UNCONTROLLED BECAUSE BOILER DUTY IS <40 MMBTU/H. Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 SULFUR RECOVERY 

UNIT

50.006 20 LT/D TOTAL SULFUR PRODUCTION LIMITED TO 20 LONG TONS PER DAY (LT/D) BASED ON 98.5 SRU EFFICIENCY. Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZER 0.03 LB/H 98.5 U

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 IC ENGINE 

COMPRESSOR, (5)

17.13 800 HP FIVE 800 HP INLET GAS COMPRESSOR ENGINES Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION PRACTICE 2.14 LB/H 0 U

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 IC ENGINE 

COMPRESSOR, (5)

17.13 800 HP FIVE 800 HP INLET GAS COMPRESSOR ENGINES Formaldehyde P GOOD COMBUSTION PRACTICE 0.34 LB/H 0 U

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 FLARE, LOW 

PRESSURE

50.008 Volatile Organic Compounds 

(VOC)

A 98% VOC DESTRUCTION OF FLARE MEETS 40 CFR 60.18. FLARE IS THE CONTROL. 3.82 LB/H 98 U

TX-0408 INDIAN ROCK 

GATHERING 

COMPANY LP

TX 2819 211112 FLARE, HIGH 

PRESSURE

50.008 Volatile Organic Compounds 

(VOC)

A 98% VOC DESTRUCTION OF FLARE MEETS 40 CFR 60.18. FLARE IS THE CONTROL. 1.08 LB/H 98 U

TX-0440 CORPUS CHRISTI 

LNG

TX 4922 221210 SUBMERGED 

COMBUSTION 

VAPORIZERS (SVCS) -

16

19.9 THE MAJOR SOURCE OF EMISSIONS IS FROM THE 16 SCV, IS A WATER BATH TYPE WITH A STAINLESS STEEL WATER BASIN. THE EMISSIONS ARE PER VAPORIZER Volatile Organic Compounds 

(VOC)

P GOOD COMBUSTION DESIGN AND OPERATIONS WHILE FIRING NATURAL GAS WITH VOC 0.62 LB/H 0 U

TX-0440 CORPUS CHRISTI 

LNG

TX 4922 221210 DIESEL FIRWATER 

PUMP

99.999 660 HP Volatile Organic Compounds 

(VOC)

N 0.18 LB/H 0 U

TX-0440 CORPUS CHRISTI 

LNG

TX 4922 221210 DIESEL FIREWATER 

BOOSTER PUMP

99.999 525 HP Volatile Organic Compounds 

(VOC)

N 0.07 LB/H 0 U

TX-0440 CORPUS CHRISTI 

LNG

TX 4922 221210 EMERGENCY DIESEL 

GENERATOR

19.9 1500 KW Volatile Organic Compounds 

(VOC)

N 1.67 LB/H 0 U

TX-0440 CORPUS CHRISTI 

LNG

TX 4922 221210 FUGITIVES (4) 50.007 Volatile Organic Compounds 

(VOC)

N 1.96 LB/H 0 U

TX-0454 EL PASO NATURAL 

GAS CORNUDAS 

COMPRESSOR 

STATION

TX 4922 486210 FUGITIVES (4) 64.002 Volatile Organic Compounds 

(VOC)

N 0.13 LB/H 0 U

TX-0454 EL PASO NATURAL 

GAS CORNUDAS 

COMPRESSOR 

STATION

TX 4922 486210 TURBINES (2) 16.11 10011 hp EMISSIONS PER TURBINE. BACT FOR ALL POLLUTANTS; PSD FOR NOX. NOX WILL CONTROLLED USING DRY LOW NOX COMBUSTORS IN THE TURBINES. NOX WILL NOT EXCEED 25 PPM CORRECTED TO 15% O2. DUE TO THE Volatile Organic Compounds 

(VOC)

N 0.26 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 GLYCOL VENT 64.003 Benzene N 0.34 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 GLYCOL VENT 64.003 Volatile Organic Compounds 

(VOC)

N 9.42 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 COOPER-BESSEMER 

ENGINE 3105 HP

17.19 3105 HP Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 10.94 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 HOT OIL HEATER 19.6 32.5 MMBTU/H Volatile Organic Compounds 

(VOC)

N 0.21 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 FUGITIVES (4) 64.002 Volatile Organic Compounds 

(VOC)

N 9.08 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 FUGITIVES 64.002 Volatile Organic Compounds 

(VOC)

N 9.33 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 FLARES (2) 19.31 INLET GAS COMPOSITION AND VOLUMES HAVE CHANGED OVER THE YEARS SINCE REINJECTION OF CO2 WAS STARTED. IN 1998 THE SO2 EMISSION WERE REDUCED FROM 1020 T/YR TO APPROXIMATELY 174 T/YR IN PERMVolatile Organic Compounds 

(VOC)

P 42.82 LB/H 98 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 HP TEG FIREBOX 19.6 Volatile Organic Compounds 

(VOC)

N 0.02 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 COOPER-BESSEMER 

ENGINE

17.19 2400 HP Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 6.35 LB/H 0 U

Attachment 1, page 12 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 CLARK ENGINE (2) 17.19 2000 HP EMISSIONS ARE PER ENGINE Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 1.32 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 INGERSOLL-RAND 

ENGINE

17.29 440 HP Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 0.48 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 HOT OIL HEATER 19.6 12 MMBTU/H Volatile Organic Compounds 

(VOC)

N 0.08 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 INGERSOLL-RAND 

ENGINE 1330 HP

17.19 1330 HP Volatile Organic Compounds 

(VOC)

P LEAN COMBUSTION 1.76 LB/H 0 U

TX-0465 SALT CREEK GAS 

PLANT

TX 1321 221210 GLYCOL REBOILER 19.6 2.5 MMBUT/H Volatile Organic Compounds 

(VOC)

N 0.02 LB/H 0 U

TX-0473 DOERING RANCH 

GAS PLANT

TX 1311 211111 Natural Gas Plant 50.999 0.45 MMscfd Site will not vent or flare more than 0.3 long tons per day of total sulfur. Based on 0.45 MMscfd gas throughput with an H2S content of 6,450 ppm, worst case if all vented, sulfur vented would be 0.11 ltpd. Volatile Organic Compounds 

(VOC)

A Flare is used. 13.29 T/YR 98 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 PARTS WASHER 99.999 Volatile Organic Compounds 

(VOC)

N 0.02 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 FUGITIVES (4) 50.007 THE CO EMISSIONS ARE ELIGIBLE FOR PSD Volatile Organic Compounds 

(VOC)

N 0.23 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 BOILER STACK 11.39 CO EMISSIONS ARE ELIGIBLE FOR PSD Volatile Organic Compounds 

(VOC)

N 33.18 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 DIESEL FUEL TANK 42.005 Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 DIESEL FUEL TANK 42.005 Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 EMERGENCY 

GENERATOR

19.8 CO EMISSIONS ARE ELIGIBLE FOR PSD Volatile Organic Compounds 

(VOC)

N 1.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 FLARE (NORMAL 

OPERATION)

19.31 Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 EMERGENCY 

GENERATOR TANK

19.8 Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 PROCESS STEAM 

VENT

64.003 DS Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0481 AIR PRODUCTS 

BAYTOWN I I

TX 492 486210 MSS PROCESS 

STEAM VENT

64.003 Volatile Organic Compounds 

(VOC)

N 0.01 LB/H 0 U

TX-0501 TEXSTAR GAS 

PROCESS FACILITY

TX 132 221210 TURBINE EXHAUST 

DUCT BURNER (3)

13.31 EMISSIONS ARE PER BURNER Volatile Organic Compounds 

(VOC)

N 0.18 LB/H 0 U

TX-0501 TEXSTAR GAS 

PROCESS FACILITY

TX 132 221210 POWER STEAM 

BOILER

13.31 93 MMBTU/H Volatile Organic Compounds 

(VOC)

N 0.46 LB/H 0 U

TX-0501 TEXSTAR GAS 

PROCESS FACILITY

TX 132 221210 TREATED GAS 

COMPRESSOR 

ENGINE STACK WITH 

CATALYTIC 

CONVERTER 

WAUKESHA L7042GSI

17.13 875 HP Volatile Organic Compounds 

(VOC)

N 2.7 LB/H 0 U

TX-0501 TEXSTAR GAS 

PROCESS FACILITY

TX 132 221210 BOTTOM HEATERS 

(2)

19.6 15 MMBTU/H EMISSIONS ARE PER HEATER Volatile Organic Compounds 

(VOC)

N 0.09 LB/H 0 U

TX-0501 TEXSTAR GAS 

PROCESS FACILITY

TX 132 221210 ALLISON 501KB GAS 

TURBINE 

GENERATOR

15.9 Volatile Organic Compounds 

(VOC)

N 0.11 LB/H 0 U

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 TURBINES WITH 165 

MMBTU/HR DUCT 

BURNERS

15.11 75 MW Volatile Organic Compounds 

(VOC)

P USE OF NATURAL GAS 3.5 LB/H 0 U

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 TURBINES WITH 165 

MMBTU/HR DUCT 

BURNERS

15.11 75 MW Formaldehyde N 0.3 LB/H 0 U

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 TURBINES WITHOUT 

165 MMBTU/HR 

DUCT BURNERS

15.11 75 MW Volatile Organic Compounds 

(VOC)

N 1.9 LB/H 0 U

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 TURBINES WITHOUT 

165 MMBTU/HR 

DUCT BURNERS

15.11 75 MW Formaldehyde N 0.3 LB/H 0 U

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 STARTUP, 

SHUTDOWN, 

MAINTENANCE

15.11 75 MW Volatile Organic Compounds 

(VOC)

N 60 LB/H 0 U

Attachment 1, page 13 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

TX-0504 NAVASOTA POWER 

GENERATION 

FACILITY

TX 4924 221210 STARTUP, 

SHUTDOWN, 

MAINTENANCE

15.11 75 MW Formaldehyde N 0.3 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 FURNACE 90.015 THE FURNACE WILL GENERATE EMISSIONS OF CO, NOX, PM/PM10, SO2, AND VOC; CERTAINTEED PROPOSES TO LIMIT EMISSIONS FROM THE FURNACE AS FOLLOWS: NO MORE THAN 1.40 LBS NOX / TON OF GLASS PRODUCVolatile Organic Compounds 

(VOC)

N 0.73 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 BI/LI LINE FREHEAT 

FUGITIVES (8)

90.015 EMISSIONS ARE PER LINE (BI AND LI) Volatile Organic Compounds 

(VOC)

N 0.04 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 BI STACK 90.015 BI LINE FIBER AND MAT FORMING, CURING, AND COOLING: THIS FIBER AND MAT FORMING, CURING, AND COOLING PROCESS GENERATES PRODUCTS OF COMBUSTION, VOC, NH3, FORMALDEHYDE, AND PHENOL EMISSIOVolatile Organic Compounds 

(VOC)

N 23.32 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 BI STACK 90.015 BI LINE FIBER AND MAT FORMING, CURING, AND COOLING: THIS FIBER AND MAT FORMING, CURING, AND COOLING PROCESS GENERATES PRODUCTS OF COMBUSTION, VOC, NH3, FORMALDEHYDE, AND PHENOL EMISSIOFormaldehyde N 7.07 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 IS LINE FIBER 

FOAMING WET 

SCRUBBER STACK

90.016 IS LINE FIBER FORMING: THESE OPERATIONS RESULT IN EMISSIONS OF CO, NOX, PM/PM10, SO2 , AND VOC. PRODUCTS OF COMBUSTION EMISSIONS FROM THE FIBERIZERS WILL BE REDUCED BY FIRING ONLY SWEET NATVolatile Organic Compounds 

(VOC)

N 2.49 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 BI LINE PRODUCT 

LABELING

90.015 BI LINE PRODUCT LABELING: A SMALL QUANTITY OF VOC AND HAP EMISSIONS WILL BE GENERATED FROM THE BI LINE PRODUCT LABELING AREAS. THE COMPANY PROPOSES TO MINIMIZE VOC EMISSIONS FROM THESE OVolatile Organic Compounds 

(VOC)

N 4.54 LB/H 0 U

TX-0505 CERTAINTEED 

INSULATION FIBER 

GLASS AND 

DUCTLINER 

MANUFACTURI

TX 1793 221210 BI LINE PRODUCT 

LABELING

90.015 BI LINE PRODUCT LABELING: A SMALL QUANTITY OF VOC AND HAP EMISSIONS WILL BE GENERATED FROM THE BI LINE PRODUCT LABELING AREAS. THE COMPANY PROPOSES TO MINIMIZE VOC EMISSIONS FROM THESE OHazardous Air Pollutants 

(HAP)

N 1.04 LB/H 0 U

TX-0509 PONDEROSA PINE 

ENERGY PARTNERS 

COGENERATION 

FACILITY

TX 4924 221210 TURBINE AND 375 

MMBTU/HR HEAT 

RECOVERY STEAM 

SYSTEM

15.11 250 MW Volatile Organic Compounds 

(VOC)

N 30 LB/H 0 U

TX-0518 VALERO HEAVY OIL 

CRACKER

TX 4924 221210 EMISSIONS 11.11 HOC	THE SO2 EMISSIONS ARE LIMITED TO 50 PPM, CO EMISSIONS TO 500 PPM, 

AND NOX EMISSIONS TO 150 PPM HOURLY AND 100 PPM ANNUALLY, ALL OF WHICH 

MEET OR EXCEED BACT. CO, O2, NOX, AND SO2 ARE MONITORED WITH CEMS. THE PH 

OF THE SCRUBBING SOLUTION FOR THE CAUSTIC SCRUBBER IS MONITORED 

CONTINUOUSLY. THE SULFURIC ACID EMISSION CAP IS BASED ON A MAXIMUM OF 0.35 

LB SULFURIC ACID EMISSIONS PER 1000 POUND COKE BURN OFF. THERE HAVE BEEN 

SEVERAL STATE PERMIT ACTIONS WHERE SULFURIC ACID EMISSIONS WERE SHOWN AND 

THE PROPOSED VALUE IS CONSISTENT WITH THOSE DETERMINATIONS. THIS WAS 

DEEMED BACT IN THE 2004 AMENDMENT AND STILL MEETS BACT.





DIESEL ENGINES THE DIESEL ENGINES RANGE FROM 272 TO 525 HORSE POWER (HP) 

AND FROM 5.6 TO 8.0 G/HP-HR NOX. THE CAP CONTRIBUTIONS ARE CALCULATED 

BASED ON PAST HOURS OF OPERATION THAT RANGE FROM 15 TO 4,348 HOURS/YR. 

THE HOURS/YR ARE FOR CALCULATION PURPOSES AND ARE NOT OPERATIONAL 

LIMITATIONS. SEE TABLE D-1 IN THE CONFIDENTIAL SECTION FOR MORE DETAILS. THE 

ENGINES ARE PREEXISTING AND CONTROLLING FURTHER WOULD BE ECONOMICALLY 

UNREASONABLE. 


FUGITIVES ARE MONITORED BY EITHER A 28VHP PROGRAM, OR AN AVO PROGRAM FOR 

STREAMS IN RICH AMINE AND H2S SERVICE. BACT IS APPLIED.





PBR 71401 (FUGITIVES)	FUGITIVES CONTROLLED WITH 28 VHP LDAR. BACT IS APPLIED.





PBR 71288 INTERNAL FLOATING ROOF TANKS WITH MECHANICAL PRIMARY SEALS, 

Benzene N 14.6 LB/H 0 U

Attachment 1, page 14 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

TX-0518 VALERO HEAVY OIL 

CRACKER

TX 4924 221210 EMISSIONS 11.11 HOC	THE SO2 EMISSIONS ARE LIMITED TO 50 PPM, CO EMISSIONS TO 500 PPM, 

AND NOX EMISSIONS TO 150 PPM HOURLY AND 100 PPM ANNUALLY, ALL OF WHICH 

MEET OR EXCEED BACT. CO, O2, NOX, AND SO2 ARE MONITORED WITH CEMS. THE PH 

OF THE SCRUBBING SOLUTION FOR THE CAUSTIC SCRUBBER IS MONITORED 

CONTINUOUSLY. THE SULFURIC ACID EMISSION CAP IS BASED ON A MAXIMUM OF 0.35 

LB SULFURIC ACID EMISSIONS PER 1000 POUND COKE BURN OFF. THERE HAVE BEEN 

SEVERAL STATE PERMIT ACTIONS WHERE SULFURIC ACID EMISSIONS WERE SHOWN AND 

THE PROPOSED VALUE IS CONSISTENT WITH THOSE DETERMINATIONS. THIS WAS 

DEEMED BACT IN THE 2004 AMENDMENT AND STILL MEETS BACT.





DIESEL ENGINES THE DIESEL ENGINES RANGE FROM 272 TO 525 HORSE POWER (HP) 

AND FROM 5.6 TO 8.0 G/HP-HR NOX. THE CAP CONTRIBUTIONS ARE CALCULATED 

BASED ON PAST HOURS OF OPERATION THAT RANGE FROM 15 TO 4,348 HOURS/YR. 

THE HOURS/YR ARE FOR CALCULATION PURPOSES AND ARE NOT OPERATIONAL 

LIMITATIONS. SEE TABLE D-1 IN THE CONFIDENTIAL SECTION FOR MORE DETAILS. THE 

ENGINES ARE PREEXISTING AND CONTROLLING FURTHER WOULD BE ECONOMICALLY 

UNREASONABLE. 


FUGITIVES ARE MONITORED BY EITHER A 28VHP PROGRAM, OR AN AVO PROGRAM FOR 

STREAMS IN RICH AMINE AND H2S SERVICE. BACT IS APPLIED.





PBR 71401 (FUGITIVES)	FUGITIVES CONTROLLED WITH 28 VHP LDAR. BACT IS APPLIED.





PBR 71288 INTERNAL FLOATING ROOF TANKS WITH MECHANICAL PRIMARY SEALS, 

Volatile Organic Compounds 

(VOC)

N 1201 LB/H 0 U

TX-0522 VIRDIS LANDFILL GASTO-ENERGY FACILITYTX 492 221210 ENGINES (4) 19.8 EACH ENGINE WILL PRODUCE APPROXIMATELY 1,664 KW AND THE TOTAL FACILITY 

OUTPUT POTENTIAL WILL BE 11.65 MW.





EMISSIONS ARE PER ENGINE (4)

Volatile Organic Compounds 

(VOC)

N 0.83 LB/H 0 U

WI-0251 ENBRIDGE ENERGY WI 4612 211111 T36-T40 CRUDE OIL 

STORAGE TANKS

42.006 8,673,426 GAL CAPACITY EACH. EXTERNAL FLOATING ROOF TANKS.


UP TO 200 TURNOVERS / YEAR.

Volatile Organic Compounds 

(VOC)

B EXTERNAL FLOATING ROOF TANK0.53 T/VOC/MO

.

0

WI-0251 ENBRIDGE ENERGY WI 4612 211111 F01 - NEW AND 

MODIFIED TANKS, 

NEW PIPELINES, AND 

ASSOCIATED 

FUGITIVE VOC

42.006 VOC LEAKS FROM NEW AND MODIFIED TANK PIPING, NEW PIPING MANIFOLDS, AND OTHER NEW PIPING, PUMPS, VALVES , ETC. ASSOCIATED WITH THE NEW PIPELINES. Volatile Organic Compounds 

(VOC)

P USE OF AN INSTRUMENT BASED LEAK DETECTION AND REPAIR (LDAR) PROGRAM, COM0 0

WV-0020 COLUMBIA GAS 

TRANSMISSIONS 

LOST RIVER

WV 4922 486210 IC ENGINE, NATURAL 

GAS, # 10

17.13 4640 HP Compressor No. 10 shall be powered by a Clark TLAD-10 


natural gas-fired compressor engine. Compressor Engine No. 


10 shall not exceed the maximum operating limit of 


40,640,400 brake horsepower-hours per year.

Volatile Organic Compounds 

(VOC)

N 0.7 G/B-HP-H 0

WY-0040 CHEVRON USA - 

PAINTER CENTRAL 

STATION

WY 1311 211111 ENGINES, 

COMPRESSOR, 2 

EACH

17.13 2650 BHP, EACH Volatile Organic Compounds 

(VOC)

P ‘‘CLEAN BURN‘‘ TECHNOLOGY 0.6 G/B-HP-H 0

WY-0049 WESTERN GAS 

RESOURCES - 

HILIGHT GAS PLANT

WY 1321 211112 ENGINES, 

COMPRESSOR, 2 EA

17.13 1650 HP WAUKESHA 7044 GSI TURBO CHARGED COMPRESSOR ENGINES. Volatile Organic Compounds 

(VOC)

A 3 - WAY CATALYST SYSTEM AND AIR/FUEL RATIO CONTRO-LLER 1 G/HP-H 0

WY-0051 UNION PACIFIC 

RESOURCES - 

PATRICK DRAW GAS 

PLANT

WY 1321 211112 ENGINE, 

COMPRESSOR, 9 EA

17.13 3200 HP WHITE SUPERIOR 2416G ENGINES. Volatile Organic Compounds 

(VOC)

B ULTRA LOW NOX LEAN BURN TECHNOLOGY AND CATALYTIC CONVERTER. 0.3 G/HP-H 0

WY-0051 UNION PACIFIC 

RESOURCES - 

PATRICK DRAW GAS 

PLANT

WY 1321 211112 COMPRESSOR, 

ENGINES, 2 EA

17.13 1200 HP WHITE SUPERIOR 2408G ENGINES. Volatile Organic Compounds 

(VOC)

P ULTRA LOW NOX LEAN BURN TECHNOLOGY. 0.5 G/HP-H 0

WY-0052 UNION PACIFIC 

RESOURCES - 

PATRICK DRAW GAS 

PLANT

WY 1321 211112 ENGINES, 

COMPRESSOR, 9 EA

17.13 3200 HP WHITE SUPERIOR 2416G ENGINES. Volatile Organic Compounds 

(VOC)

B ULTRA LOW NOX LEAN BURN TECHNOLOGY. CATALYTIC CONVERTER. 0.3 G/B-HP-H 0

WY-0052 UNION PACIFIC 

RESOURCES - 

PATRICK DRAW GAS 

PLANT

WY 1321 211112 ENGINES, 

COMPRESSOR, 2 EA

17.13 1200 HP WHITE SUPERIOR 2408G ENGINES. Volatile Organic Compounds 

(VOC)

P ULTRA LOW NOX LEAN BURN TECHNOLOGY. 0.5 G/B-HP-H 0

WY-0060 WILLIAMS FIELD 

SERVICES CO./ECHO 

SPRINGS GAS PLANT

WY 1321 211112 AMINE UNIT 50.006 Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZER 98 % 

REDUCTIO

N

0 Y

WY-0067 ECHO SPRINGS GAS 

PLANT

WY 1321 211112 TURBINES S35-S36 16.11 12555 HP TWO (2) 12,555 HP SOLAR MARS 100-15000S TURBINES Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES 25 PPMV 0

Attachment 1, page 15 April 3, 2012
ATTACHMENT 1. APRIL 3, 2012, EXTRACTION FROM RBLC DATABASE

RBLCID FACILITY_NAME FACILITY_S

TATE

SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_

TYPE

THROUGHPUT THROUGHPUT_

UNIT

PROCESS_NOTES" POLLUTANT CONTROL_M

ETHOD_COD

E

CONTROL_METHOD_D

ESCRIPTION

EMISSION_

LIMIT_1

EMISSION_

LIMIT_1_U

NIT

PERCENT_

EFFICIENC

Y

COMPLIANCE_

VERIFIED

WY-0067 ECHO SPRINGS GAS 

PLANT

WY 1321 211112 TURBINE S37 16.21 16162 HP 12,555 HP SOLAR MARS100-15000S OR 16,162 HP SOLAR TITAN 130-20502S TURBINE Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES 25 PPV 0

WY-0067 ECHO SPRINGS GAS 

PLANT

WY 1321 211112 TURBINE S34 16.11 3856 HP SOLAR CENTAUR 40-T4700S Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES 50 PPMV 0

WY-0067 ECHO SPRINGS GAS 

PLANT

WY 1321 211112 HOT OIL HEATER S38 13.31 84 MMBTU/H Volatile Organic Compounds 

(VOC)

N GOOD COMBUSTION PRACTICES0.02 LB/MMBT

U

0

WY-0067 ECHO SPRINGS GAS 

PLANT

WY 1321 211112 AMINE UNIT VOC 

CONTROL

13.31 72 MMBTU/H Volatile Organic Compounds 

(VOC)

A THERMAL OXIDIZER 0.04 LB/MMBT

U

99 N

Attachment 1, page 16 April 3, 2012
ATTACHMENT 2

Data Collected During Development of 1999 MACT for Large Glycol Dehydration Units - Production

73 TOTAL 46.00 Number dehys greater than 5 mmscf/d

16.9743 average throughput

BTEX BTEX Emissions (tpy)

Company Docket ID

Number 

of Units

Inlet 

Conc. 

(ppmv) B T E X Total

Throughput 

(MMSCF/D)

Control 

status

(y or n)

T

('F)

P

(psig)

AmHess II-D-02, pg 37 5 800 4.700 15.900 0 19.300 39.9000 3.00 n 92 970

AmHess II-D-02, pg 44 12 420 4.900 9.200 1.400 5.000 20.5000 3.36 n 90 960

Phillips II-D-13, pg 44 4 780 11.900 21.600 0.800 11.700 46.0000 3.41 n 76 940

Exxon II-D-08, pg 77 1 1997 29.600 39.400 3.700 25.900 98.6000 4.20 n 90 1000

Marathon II-D-19, pg 77 4 620 1.900 3.000 0.200 1.800 6.9000 4.80 n 80 750

Marathon II-D-19, pg 55 1 451 1.100 5.100 0.700 5.900 12.8000 5.00 n 78 600

Maxus II-D-03, pg 12 1 420 5.600 6.800 1.000 16.400 29.8000 5.30 n 100 945

Maxus II-D-03, pg 19 1 1250 3.600 9.700 0.200 0 13.5000 5.50 n 121 980

Pogo II-D-23, pg 5 1 670 4.100 5.600 0.400 3.800 13.9000 5.50 n 92 900

Shell II-D-11, pg 31 3 800 5.000 10.000 0.900 10.000 25.9000 7.20 n 100 1050

AmHess II-D-02, pg 9 2 1760 10.000 16.800 0 0 26.8000 7.20 n 96 990

Kerr II-D-10, pg 125 1 343 31.000 38.100 1.400 16.700 87.2000 8.00 n 80 480

Oxy II-D-06, pg 17 2 380 10.202 9.241 0 1.391 20.8335 8.40 n 96 850

Shell II-D-11, pg 32 1 310 4.600 6.400 0.900 4.900 16.8000 9.10 n 100 1050

Shell II-D-11, pg 28 1 130 1.800 3.600 3.000 0 8.4000 10.00 n 80 1050*

Maxus II-D-03, pg 13 1 430 6.000 6.200 0.800 8.600 21.6000 10.00 n 90 860

Shell II-D-11, pg 57 1 318 10.600 21.500 0 20.900 53.0000 10.00 n 100 950

AmHess II-D-02, pg 38 1 700 18.400 47.200 0 77.900 143.5000 13.00 n 92 950

Marathon II-D-19, pg 67 1 1578 1.300 4.200 0.500 10.100 16.1000 15.00 n 95 1100

Shell II-D-11, pg 13 1 510 0 0 0 0 0 5.50 y 120 260

AmHess II-D-02, pg 5 1 290 0.100 0.200 0 0 0.3000 6.00 y 105 980

Oxy II-D-06, pg 9 1 40 0.100 1.000 4.000 0 5.1000 12.27 y 120 158

AmHess II-D-02, pg 8 2 830 0.200 0.800 0 0 1.0000 13.50 y 100 780

Exxon II-D-08, pg 95 1 545 0.100 0.100 0 0 0.2000 14.40 y 90 900

Kerr II-D-10, pg 54 1 116 0.016 0.055 0.001 0.002 0.0741 14.56 y 114 1310

Kerr II-D-10, pg 53 1 116 0.021 0.080 0.002 0.004 0.1056 14.59 y 86 990

Marathon II-D-19, pg 31 2 304 0.400 0.300 0 0.300 1.0000 16.00 y 92 720

Texaco II-D-24, pg 43 1 50 1.158 3.360 2.694 3.428 10.6389 17.50 y 116 430

Shell II-D-11, pg 56 2 578 35.400 153.500 16.600 163.600 369.1000 30.00 n 90 225

Phillips II-D-13, pg 38 5 810 46.100 63.400 6.500 35.300 151.3000 27.40 n 85 885

Exxon II-D-08, pg 112 1 640 42.400 10.700 0 6.700 59.8000 31.70 n 88 960

Maxus II-D-03, pg 18 1 1250 10.100 28.200 0.600 0 38.9000 26.50 n 121 980

Shell II-D-11, pg 33 1 1201 21.700 28.600 3.500 40.900 94.7000 42.00 y 90 1080

Shell II-D-11, pg 29 1 1270 0.368 1.027 0.022 0.063 1.4803 23.00 y 90 900

Amoco II-D-15, pg 62 1 41 0.100 0 0 0 0.1000 36.00 y 120 430

Marathon II-D-19, pg 57 1 208 12.300 60.600 11.600 99.500 184.0000 180.00 n 90 935

AmHess II-D-02, pg 6 1 720 1.100 5.400 0 0 6.5000 67.50 y 90 750

Marathon II-D-19, pg 33 3 346 0.300 0.300 0 2.400 3.0000 60.00 y 74 1058

Amoco II-D-15, pg 63 1 41 0.100 0.100 0 0.100 0.3000 70.00 y 120 430

Attachment 2, page 1 4/11/2012
ATTACHMENT 3

Data Collected During Development of 1999 MACT for Large Glycol Dehydration Units - Transmission and Storage

64 with throughput greater than 5 MMscf/d

64 total dehys 107 average throughput

BTEX Reported BTEX Emissions (tpy) BTEX Emissions Adjusted to Full Time Operation (tpy)

Company Docket ID

Number 

of Units

Inlet 

Conc. 

(ppmv)

Hours of 

operation B T E X Total B T E X Total

Throughput 

(MMSCF/D)

Control 

status

(y or n)

Temp. Pressure

KN08 IV-G-27, pg 26 1 39.96 8,760 1.747 2.956 4.239 5.382 14.324 1.747 2.956 4.239 5.382 14.324 25.0 N 100 850

KERMIT_1 KERMIT_1 1 59.98 8,760 0.987 3.650 3.414 9.599 17.650 0.987 3.650 3.414 9.599 17.650 40.0 Y 105 335

INEZ_1 INEZ_1 1 29.98 8,760 0.568 1.038 0.918 1.186 3.709 0.568 1.038 0.918 1.186 3.709 10.0 Y 90 300

YORK_1 YORK_1 1 120 8,760 3.148 9.238 1.487 5.722 19.595 3.148 9.238 1.487 5.722 19.595 10.0 Y 100 220

WILL03 IV-G-24, pg 5 1 7 8,760 1.108 1.959 0 1.277 4.343 1.108 1.959 0 1.277 4.343 40.0 N 83 375

KN08 (maximum) IV-G-27, pg 18 1 39.96 8,760 1.199 3.102 4.534 5.806 14.640 1.199 3.102 4.534 5.806 14.640 25.0 N 100 850

BRINK_1 BRINK_1 1 96 1,000 1.808 1.286 0.393 0.531 4.016 15.834 11.261 3.440 4.649 35.184 20.0 Y 60 210

NORAM07 IV-G-31, pg 21 1 24 8,760 1.870 5.367 0 9.124 16.362 1.870 5.367 0 9.124 16.362 50.0 N 56 309

WILL02 IV-G-24, pg 3 1 58 4,380 2.103 5.465 0.795 8.975 17.338 4.206 10.930 1.591 17.950 34.677 54.0 N 70 565

ARTMAS_1 ARTMAS_1 1 43 5,000 2.148 1.811 1.603 2.340 7.902 3.764 3.173 2.808 4.099 13.844 80.0 Y 80 600

ARTMAS_2 ARTMAS_2 1 43 5,000 2.148 1.811 1.603 2.340 7.902 3.764 3.173 2.808 4.099 13.844 80.0 Y 80 600

ARTMAS_3 ARTMAS_3 1 43 5,000 2.148 1.811 1.603 2.340 7.902 3.764 3.173 2.808 4.099 13.844 80.0 Y 80 600

NORAM09 IV-G-31, pg 25 1 93 8,760 2.745 5.988 0.543 6.830 16.106 2.745 5.988 0.543 6.830 16.106 80.0 N 78 520

NORAM08 IV-G-31, pg 23 1 93 8,760 2.745 5.988 0.543 6.830 16.106 2.745 5.988 0.543 6.830 16.106 80.0 N 78 520

HLMVIL_1 HLMVIL_1 1 80 8,760 2.824 3.963 1.176 1.566 9.529 2.824 3.963 1.176 1.566 9.529 14.0 N 90 400

BEAV_1 BEAV_1 15 39.99 8,760 3.261 3.028 2.575 3.093 11.957 3.261 3.028 2.575 3.093 11.957 16.0 N 75 300

ELPASO01 IV-G-31 5 18 4,344 3.261 6.248 0 1.526 11.035 6.576 12.599 0 3.078 22.253 250.0 N 110 988

HUBLL_1 HUBLL_1 1 50 8,760 4.152 7.742 3.331 3.959 19.184 4.152 7.742 3.331 3.959 19.184 21.0 Y 80 170

KN01 IV-G-27, pg 5 1 60 8,760 4.156 7.885 0 0 12.041 4.156 7.885 0 0 12.041 70.0 N 75 550

MAYVIL_1 MAYVIL_1 1 96 5,000 5.087 4.086 1.437 2.442 13.052 8.913 7.158 2.518 4.278 22.866 40.0 N 85 600

COCO_1 COCO_1 1 96 8,760 8.143 6.321 2.344 3.828 20.635 8.143 6.321 2.344 3.828 20.635 30.0 Y 120 320

WELL_2 WELL_2 1 97 5,000 8.291 8.890 2.682 3.890 23.753 14.526 15.576 4.698 6.816 41.616 70.0 Y 60 600

MCATHR_1 MCATHR_1 1 96 5,000 9.462 7.743 2.761 4.792 24.758 16.577 13.566 4.837 8.395 43.376 155.0 Y 75 600

LAUREL_1 LAUREL_1 1 96 5,000 9.657 8.088 3.063 5.371 26.178 16.919 14.169 5.366 9.410 45.864 150.0 ? 70 450

MILEY_1 MILEY_1 1 104.78 8,760 11.310 16.828 3.340 7.394 38.872 11.310 16.828 3.340 7.394 38.872 16.0 Y 80 250

BRINK_2 BRINK_2 1 96 5,000 12.686 9.262 2.627 3.325 27.899 22.225 16.226 4.602 5.825 48.879 20.0 Y 70 325

WELL_1 WELL_1 1 92 5,000 12.986 9.737 4.051 6.047 32.820 22.751 17.059 7.097 10.594 57.501 140.0 Y 60 600

NORAM11 IV-G-31, pg 29 1 40 8,760 13.396 0 0 0 13.396 13.396 0 0 0 13.396 35.0 N 65 719

KN06 IV-G-27, pg 14 1 130 8,760 22.538 42.227 34.846 66.859 166.471 22.538 42.227 34.846 66.859 166.471 80.0 Y 68 550

BENTON_1 BENTON_1 1 96 5,000 23.470 19.293 7.031 11.821 61.614 41.119 33.801 12.318 20.711 107.948 250.0 Y 75 500

PAVNIA_2 PAVNIA_2 1 121 5,000 23.727 23.249 5.447 8.088 60.511 41.570 40.733 9.542 14.171 106.016 250.0 Y 75 700

PAVNIA_1 PAVNIA_1 1 121 5,000 23.727 23.249 5.447 8.088 60.511 41.570 40.733 9.542 14.171 106.016 250.0 Y 75 700

HOLMES_2 HOLMES_2 1 87 5,000 24.032 15.670 6.303 8.503 54.508 42.104 27.453 11.043 14.897 95.498 115.0 Y 80 750

HOLMES_1 HOLMES_1 1 65 5,000 26.697 10.303 7.624 9.212 53.836 46.774 18.051 13.357 16.139 94.320 85.0 Y 80 750

GLADY_2 GLADY_2 1 96 8,760 27.074 21.231 6.688 11.031 66.024 27.074 21.231 6.688 11.031 66.024 156.0 Y 54 800

GLADY_1 GLADY_1 1 96 8,760 27.084 21.238 6.690 11.035 66.046 27.084 21.238 6.690 11.035 66.046 156.0 Y 54 800

NORAM01 IV-G-31, pg 4 1 214 8,760 33.483 21.133 0.824 17.359 72.800 33.483 21.133 0.824 17.359 72.800 70.0 Y 72 380

KN07 IV-G-27, pg 16 1 70 8,760 40.607 76.366 63.345 163.130 343.449 40.607 76.366 63.345 163.130 343.449 300.0 Y 68 550

WEAVER_1 WEAVER_1 1 121 5,000 43.973 43.932 10.571 15.648 114.124 77.041 76.969 18.521 27.415 199.946 440.0 Y 70 650

KN05 IV-G-27, pg 12 1 130 8,760 44.688 83.183 68.082 129.534 325.486 44.688 83.183 68.082 129.534 325.486 150.0 Y 68 550

KN02 IV-G-27, pg 6 1 100 8,760 76.903 101.698 0 4.451 183.052 76.903 101.698 0 4.451 183.052 120.0 N 62 340

NORAM03 IV-G-31, pg 10 1 225 8,760 144.374 21.496 28.711 52.531 247.111 144.374 21.496 28.711 52.531 247.111 165.0 Y 70 1,200

NORAM04 IV-G-31, pg 13 1 225 8,760 144.374 21.496 28.711 52.531 247.111 144.374 21.496 28.711 52.531 247.111 165.0 Y 70 1,200

NORAM05 IV-G-31, pg 16 1 225 8,760 144.374 21.496 28.711 52.531 247.111 144.374 21.496 28.711 52.531 247.111 165.0 Y 70 1,200

STINGRAY IV-G-28, pg 3 1 230 8,760 156.334 369.668 59.579 345.460 931.042 156.334 369.668 59.579 345.460 931.042 800.0 Y 75 850

NORAM02 IV-G-31, pg 7 1 225 8,760 171.481 26.614 40.000 72.745 310.840 171.481 26.614 40.000 72.745 310.840 200.0 Y 70 900

Attachment 3, page 1 4/11/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

Calculation of Incremental Cost Effectiveness for Emission Reduction of 98 percent.

Average Incremental ER 3.50 tpy

Annual Cost of Combustor = $19,580 /yr

MACT floor level of control 95% Average ICE = 45,659 $/ton

Above the floor level of control 98.00% Range of ICE = $360.31 $/ton (Min)

$204,918 $/ton (Max)

Number of Dehys = 92

Number less than $5,000/ton = 22

Percent less than $5,000/ton = 24%

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEI11191_000023_000022_000011 WQPUEBLO PLANT 0.850000024 5.523599997 110.4719999 104.9483999 110.3615279 5.413127997 $3,617

NEI11211_000042_000026_000063 CONROE COMPRESSOR STATION 1.725800037 12.2191004 244.382008 232.1629076 244.137626 11.97471839 $1,635

NEI12047_000011_000143_000127 WASKOM GAS PLANT 0.2368 0.2833 5.665999996 5.382699996 5.660333996 0.277634 $70,524

NEI12503_000011_000043_000047 BENEDUM GAS PLANT 0.059999999 0.219999999 4.399999976 4.179999977 4.395599976 0.215599999 $90,816

NEI12819_000001_000001_000001 PINEHURST COMPRESSOR STATION 0.663999975 0.985899983 19.71799966 18.73209967 19.69828166 0.966181983 $20,265

NEI13085_000015_000030_000010 LAKE CREEK PLANT 0.162200004 0.247100005 4.942000101 4.694900096 4.937058101 0.242158005 $80,856

NEI13271_000002_000035_000032 ALAZAN COMPRESSOR STATION 0.158000007 0.313200013 6.26400026 5.950800247 6.25773626 0.306936013 $63,791

NEI13316_000011_000007_000007 WILLOW SPRINGS PLANT 0.07 0.499999985 9.999999702 9.499999717 9.989999702 0.489999985 $39,959

NEI2CO045363_01_002_002 ENCANA - EAST MAMM CREEK CS 0.204999998 0.204999998 4.099999964 3.894999966 4.095899964 0.200899998 $97,461

NEI2CO045363_01_003_003 ENCANA - EAST MAMM CREEK CS 0.204999998 0.204999998 4.099999964 3.894999966 4.095899964 0.200899998 $97,461

NEI2CO045363_01_007_007 ENCANA - EAST MAMM CREEK CS 3.285 16.87 337.4 320.53 337.0626 16.5326 $1,184

NEI2CO045365_01_033_029 WILLIAMS PROD RMT CORP - PARACHUTE 0.626 1.336 26.72 25.384 26.69328 1.30928 $14,955

NEI2OK1747_55854_7026_7026 DCP MIDSTREAM LP 0.0547992 0.2776776 5.553552 5.2758744 5.547998448 0.272124048 $71,952

NEI2TX1520_000013_000004_000012 HAMILL ESTATE COMPRESSOR STATION 0.132400006 0.428800014 8.576000277 8.147200263 8.567424277 0.420224014 $46,594

NEI2TX1619_000041_000012_000014 TEAGUE GAS PLANT 0.059999999 0.129999997 2.599999942 2.469999945 2.597399942 0.127399997 $153,688

NEI2TX20371_000008_000008_000008 WHELAN N COMP STATION 0.132799998 0.140999998 2.819999959 2.678999961 2.817179959 0.138179998 $141,698

NEI2TX39139_000006_000002_000001 TOM O'CONNER COMPRESSOR STATION 0.162100002 0.631300005 12.6260001 11.9947001 12.6133741 0.618674005 $31,648

NEI2TX39520_000005_000003_000001 BOA GAS TREATING PLANT 0.286799997 0.338699998 6.773999953 6.435299955 6.767225953 0.331925998 $58,989

NEI2TX42343_000009_000003_000002 PERRY COMP COMMON POINT 0.103200004 0.149100004 2.982000075 2.832900072 2.979018075 0.146118004 $134,000

NEI2TX4973_000019_000053_000054 BRIDGEPORT 3.581899881 14.40159968 288.0319935 273.6303938 287.7439615 14.11356768 $1,387

NEI6094_09_09_09 CHEVRON USA INC/DELTA DUCK STN 1 0.15648 0.74844 14.9688 14.22036 14.9538312 0.7334712 $26,695

NEI6453_000001_000034_000024 EXXON MOBIL SARITA COMPRE 0.163299993 0.530999988 10.61999975 10.08899976 10.60937975 0.520379988 $37,626

NEI6453_000003_000032_000029 EXXON MOBIL SARITA COMPRE 1.089699984 3.414100023 68.28200046 64.86790044 68.21371846 3.345818023 $5,852

NEI6456_000042_000022_000052 KING RANCH PLANT 13.44029999 14.9337 298.6739999 283.7402999 298.3753259 14.635026 $1,338

NEI6456_000045_000019_000049 KING RANCH PLANT 6.767099857 29.83200002 596.6400003 566.8080003 596.0433603 29.23536002 $670

NEI6483_000034_000023_000061 KATY GAS PLANT 0.289799988 1.163800001 23.27600002 22.11220002 23.25272402 1.140524001 $17,167

NEI6509_000036_000015_000011 CANADIAN PLANT 0.062920008 0.318827224 6.37654448 6.057717256 6.370167936 0.31245068 $62,665

NEI7410_000079_000025_000022 SPRINGTOWN GAS PLANT 0.515999973 1.614399964 32.28799928 30.67359932 32.25571128 1.582111965 $12,376

NEI7421_000019_000015_000027 VIBORES COMPRESSOR STATION 9.137700081 19.29670012 385.9340024 366.6373023 385.5480684 18.91076612 $1,035

NEI7449_000031_000024_000029 BRAZORIA NATURAL GAS BOOSTER 0.0891261 0.4516183 9.032366 8.5807477 9.023333634 0.442585934 $44,240

NEI7694_000012_000042_000016 HEADLEE DEV GAS PLANT 0.082000002 0.182000001 3.640000029 3.458000027 3.636360029 0.178360001 $109,777

NEI7785_000002_000002_000002 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.22875998 0.550759999 $35,551

NEI7785_000006_000006_000006 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.22875998 0.550759999 $35,551

NEI7785_000007_000007_000007 OYSTER LAKE FACILITY 0.5 1.729999989 34.59999979 32.8699998 34.56539979 1.695399989 $11,549

NEI7787_000008_000006_000007 TRAWICK CTRL TREATING STN 2.468699932 3.285399925 65.7079985 62.42259857 65.6422905 3.219691926 $6,081

NEI7787_000010_000007_000007 TRAWICK CTRL TREATING STN 0.981700003 1.309000012 26.18000023 24.87100022 26.15382023 1.282820011 $15,263

NEI7787_000012_000008_000007 TRAWICK CTRL TREATING STN 1.052999973 1.380999973 27.61999946 26.23899949 27.59237946 1.353379974 $14,467

NEI7839_000003_000003_000003 TRAWICK WEST STATION 17.1480999 27.39659971 547.9319942 520.5353945 547.3840622 26.84866772 $729

NEI7998_000017_000024_000015 SONORA GAS PLANT 0.519999981 1.769999951 35.39999902 33.62999907 35.36459902 1.734599952 $11,288

NEIAL0530005_01_008_008 VINTAGE PETROLEUM INC 21.4 55.45 1109 1053.55 1107.891 54.341 $360

NEIAL0530007_01_016_016 Escambia Operating Company LLC 0.86 3.49 69.8 66.31 69.7302 3.4202 $5,725

NEIAL10190_01_016_016 Union Oil of California 0.57 1.07 21.4 20.33 21.3786 1.0486 $18,672

NEICA0592118_1_70001_00001H AERA ENERGY LLC 0.07436 0.263045249 5.260904981 4.997859732 5.255644076 0.257784344 $75,954

NEICA1115664_2_70018_00001H SENECA RESOURCES CORP. 0.2916 1.0007 20.014 19.0133 19.993986 0.980686 $19,965

NEICO0186_01_002_002 CALPINE NATURAL GAS COMPANY-MAMM CREEK 3.09 3.09 61.8 58.71 61.7382 3.0282 $6,466

NEICO0450156_01_001_001 WILLIAM PRODUCTION RMT - RIFLE STATION 2.4825 4.8775 97.55 92.6725 97.45245 4.77995 $4,096

NEICO0450156_01_002_002 WILLIAM PRODUCTION RMT - RIFLE STATION 2.4825 4.9675 99.35 94.3825 99.25065 4.86815 $4,022

NEICO1230048_01_017_017 KERR-MCGEE ROCKY MOUNTAIN CORP - HUDSON 0.306 7.536000139 150.7200028 143.1840026 150.5692828 7.385280136 $2,651

NEICO1230048_01_018_018 KERR-MCGEE ROCKY MOUNTAIN CORP - HUDSON 0.1925 0.1925 3.85 3.6575 3.84615 0.18865 $103,789

NEICO1230057_01_021_021 KERR-MCGEE FT LUPTON COMPRESSOR STATION 0.0975 0.0975 1.95 1.8525 1.94805 0.09555 $204,918

NEICO1230184_01_006_006 KERR-MCGEE FREDERICK CS 0.224 0.224 4.48 4.256 4.47552 0.21952 $89,194

Attachment 4, page 1 4/17/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEILA0026_12_12_12 ENERVEST OPERATING LLC/LEEVILLE CS 4.01542 9.21326 184.2652 175.05194 184.0809348 9.0289948 $2,169

NEILA0075_08_08_08 STONE ENERGY CORP/LAFITTE FIELD COMPRESSOR STATION TB #5 & CAMP 0.77444 1.44932 28.9864 27.53708 28.9574136 1.4203336 $13,785

NEILA0123_02_02_02 GULFPORT ENERGY CORP/W COTE BLANCHE BAY DEHY 0.54444 1.16432 23.2864 22.12208 23.2631136 1.1410336 $17,160

NEILA0130_02_02_02 ENERVEST WEST COTE 2.9545 6.384 127.68 121.296 127.55232 6.25632 $3,130

NEILA0450042_12_12_12 SOURCE PETROLEUM INC/FAUSSE PT CS 2 1.21096 1.88588 37.7176 35.83172 37.6798824 1.8481624 $10,594

NEILA0690006_49_49_49 EXCO RESOURCES INC/BLK LAKE GAS PROC PLNT 0.1075 0.1155 2.31 2.1945 2.30769 0.11319 $172,982

NEILA0750033_44_44_44 OCEAN ENERGY, INC/MAIN PASS 69 PLATFORM B 0.2322 1.1766 23.532 22.3554 23.508468 1.153068 $16,981

NEILA0750033_45_45_45 OCEAN ENERGY, INC/MAIN PASS 69 PLATFORM B 0.2322 1.1766 23.532 22.3554 23.508468 1.153068 $16,981

NEILA0770023_43_43_43 BP AMERICA PROD CO/MORGANZA CENTRAL TANK BATTERY #1 0.1425 0.436 8.72 8.284 8.71128 0.42728 $45,824

NEILA0770023_44_44_44 BP AMERICA PROD CO/MORGANZA CENTRAL TANK BATTERY #1 1.034 3.161 63.22 60.059 63.15678 3.09778 $6,321

NEILA1010013_21_21_21 CABOT OIL & GAS CORP/BELLE ISLE BAT #1 0.0825 0.1085 2.17 2.0615 2.16783 0.10633 $184,142

NEILA1010042_22_22_22 NEXEN PETROLEUM USA INC/EUGENE ISL BLK 18 FLD 2.9315 4.3415 86.83 82.4885 86.74317 4.25467 $4,602

NEILA1090032_06_06_06 HILCORP ENERGY CO/CAILLOU ISLAND WESTSIDE CS 0.061919999 0.313759997 6.275199944 5.961439947 6.268924744 0.307484797 $63,678

NEILA13789_17_17_17 SOURCE PETROLEUM INC/FORDOCHE CS 1 CF8 TB 18 0.61284 1.04 20.8 19.76 20.7792 1.0192 $19,211

NEIMI055B915_P01S01_EU0003_SV0002 MERIT ENERGY CO. - GRANT 29 0.14157 0.23975 4.795 4.55525 4.790205 0.234955 $83,335

NEIMIB5587_P02S01_EU0014_SV0001 MERIT ENERGY COMPANY. - MAYFIELD 23 0.08139 0.13786 2.7572 2.61934 2.7544428 0.1351028 $144,926

NEIMIB9135_P01S01_EU0015_FUG002 MERIT ENERGY CO. - BEAR LAKE 13 0.14157 0.23975 4.795 4.55525 4.790205 0.234955 $83,335

NEIMIB9136_P01S01_EU0016_FUG002 MERIT ENERGY CO. - BEAR LAKE 22 0.23713 0.40161 8.0322 7.63059 8.0241678 0.3935778 $49,748

NEIMIB9142_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - CHARLTON 12 0.06194 0.10491 2.0982 1.99329 2.0961018 0.1028118 $190,444

NEIMIB9160_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - MAPLE GROVE 16 0.13096 0.22179 4.4358 4.21401 4.4313642 0.2173542 $90,083

NEIMIN6015_P01S01_EU0004_FUG004 PARTELLO COMPRESSOR STATION 0.108 0.2345 4.69 4.4555 4.68531 0.22981 $85,200

NEIMIN6015_P01S01_EU0009_FUG009 PARTELLO COMPRESSOR STATION 0.16 0.3295 6.59 6.2605 6.58341 0.32291 $60,636

NEIMIN6466_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC. - ST. KALKASKA 1-10 2.37124 4.01602 80.3204 76.30438 80.2400796 3.9356996 $4,975

NEIMIN6470_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC - USA KALKASKA 1-30 2.37124 4.01602 80.3204 76.30438 80.2400796 3.9356996 $4,975

NEIOK2038_48539_14514_14547 DCP MIDSTREAM LP 0.84 6.69 133.8 127.11 133.6662 6.5562 $2,986

NEIOK2529_53558_20110_20271 ONEOK FIELD SVC 0.05575896 0.28254088 5.6508176 5.36827672 5.645166782 0.276890062 $70,714

NEITX067CG00_000011_000018_000006 MCLEOD GAS PLANT 0.100699998 0.124799999 2.495999988 2.371199989 2.493503988 0.122303999 $160,092

NEITX157312F_000002_000002_000004 THOMPSON COMPRESSOR STATION 3 0.291599989 5.447599872 108.9519974 103.5043976 108.8430454 5.338647875 $3,668

NEITX18630_000033_000032_000030 SALT CREEK FIELD GAS PLANT 0.914699972 3.677900046 73.55800092 69.88010088 73.48444292 3.604342045 $5,432

NEITX18630_000035_000033_000032 SALT CREEK FIELD GAS PLANT 1.050899982 4.107399896 82.14799792 78.04059802 82.06584992 4.025251898 $4,864

NEITX18630_000036_000032_000019 SALT CREEK FIELD GAS PLANT 0.09042642 0.45820726 9.1641452 8.70593794 9.154981055 0.449043115 $43,604

NEITX18630_000037_000033_000019 SALT CREEK FIELD GAS PLANT 0.168549336 0.854070408 17.08140816 16.22733775 17.06432675 0.836989 $23,393

NEITX201972B_000001_000007_000007 NORTH MILTON 2.345499992 5.512599893 110.2519979 104.739398 110.1417459 5.402347895 $3,624

NEITX215294O_000012_000009_000014 MCALLEN RANCH CENTRAL FACILITY 0.200399995 0.693599997 13.87199994 13.17839994 13.85812794 0.679727997 $28,805

NEITX383004K_000011_000042_000013 MIDKIFF GAS PLANT 0.109999999 0.132999999 2.659999989 2.52699999 2.657339989 0.130339999 $150,222

NEITXRHX1519_000009_000002_000002 KATHLEEN THARP 2 0.114399999 0.405700001 8.114000019 7.708300018 8.105886019 0.397586001 $49,247

NEITXRLI0045_000002_000001_000001 TUFCO-FALLON DEL STA 1.220000029 1.63000004 32.6000008 30.97000076 32.5674008 1.597400039 $12,257

NEITXRPE0020_000001_000017_000020 PIKES PEAK PLANT 0.430000007 4.820000112 96.40000224 91.58000213 96.30360224 4.72360011 $4,145

NEITXRPE0042_000001_000018_000006 COYANOSA GAS PLANT 0.100000001 0.92 18.4 17.48 18.3816 0.9016 $21,717

NEITXRSQ0088_000002_000002_000002 JUNO COMPRESSOR STATION 0.600899994 1.345000016 26.90000031 25.5550003 26.87310031 1.318100015 $14,855

NEITXRUA0156_000012_000013_000013 INDIAN ROCK GAS PLANT 0.284000009 1.137000035 22.74000071 21.60300067 22.71726071 1.114260035 $17,572

Grand Total 328.2950767

Attachment 4, page 2 4/17/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

Calculation of Incremental Cost Effectiveness for Emission Reduction of 99 percent.

Average Incremental ER 3.53 tpy

Annual Cost of Combustor = $19,580 /yr

MACT floor level of control 95% Average ICE = 45,198 $/ton

Emission Reduction 99.00% Range of ICE = $357 $/ton (Min)

$202,848 $/ton (Max)

Number of Dehys = 92

Number less than $5,000/ton = 22

Percent less than $5,000/ton = 24%

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEI11191_000023_000022_000011 WQPUEBLO PLANT 0.850000024 5.523599997 110.4719999 104.9483999 110.4167639 5.468363997 $3,581

NEI11211_000042_000026_000063 CONROE COMPRESSOR STATION 1.725800037 12.2191004 244.382008 232.1629076 244.259817 12.0969094 $1,619

NEI12047_000011_000143_000127 WASKOM GAS PLANT 0.2368 0.2833 5.665999996 5.382699996 5.663166996 0.280467 $69,812

NEI12503_000011_000043_000047 BENEDUM GAS PLANT 0.059999999 0.219999999 4.399999976 4.179999977 4.397799976 0.217799999 $89,898

NEI12819_000001_000001_000001 PINEHURST COMPRESSOR STATION 0.663999975 0.985899983 19.71799966 18.73209967 19.70814066 0.976040983 $20,061

NEI13085_000015_000030_000010 LAKE CREEK PLANT 0.162200004 0.247100005 4.942000101 4.694900096 4.939529101 0.244629005 $80,039

NEI13271_000002_000035_000032 ALAZAN COMPRESSOR STATION 0.158000007 0.313200013 6.26400026 5.950800247 6.26086826 0.310068013 $63,147

NEI13316_000011_000007_000007 WILLOW SPRINGS PLANT 0.07 0.499999985 9.999999702 9.499999717 9.994999702 0.494999985 $39,555

NEI2CO045363_01_002_002 ENCANA - EAST MAMM CREEK CS 0.204999998 0.204999998 4.099999964 3.894999966 4.097949964 0.202949998 $96,476

NEI2CO045363_01_003_003 ENCANA - EAST MAMM CREEK CS 0.204999998 0.204999998 4.099999964 3.894999966 4.097949964 0.202949998 $96,476

NEI2CO045363_01_007_007 ENCANA - EAST MAMM CREEK CS 3.285 16.87 337.4 320.53 337.2313 16.7013 $1,172

NEI2CO045365_01_033_029 WILLIAMS PROD RMT CORP - PARACHUTE 0.626 1.336 26.72 25.384 26.70664 1.32264 $14,804

NEI2OK1747_55854_7026_7026 DCP MIDSTREAM LP 0.0547992 0.2776776 5.553552 5.2758744 5.550775224 0.274900824 $71,225

NEI2TX1520_000013_000004_000012 HAMILL ESTATE COMPRESSOR STATION 0.132400006 0.428800014 8.576000277 8.147200263 8.571712277 0.424512014 $46,123

NEI2TX1619_000041_000012_000014 TEAGUE GAS PLANT 0.059999999 0.129999997 2.599999942 2.469999945 2.598699942 0.128699997 $152,136

NEI2TX20371_000008_000008_000008 WHELAN N COMP STATION 0.132799998 0.140999998 2.819999959 2.678999961 2.818589959 0.139589998 $140,267

NEI2TX39139_000006_000002_000001 TOM O'CONNER COMPRESSOR STATION 0.162100002 0.631300005 12.6260001 11.9947001 12.6196871 0.624987005 $31,328

NEI2TX39520_000005_000003_000001 BOA GAS TREATING PLANT 0.286799997 0.338699998 6.773999953 6.435299955 6.770612953 0.335312998 $58,393

NEI2TX42343_000009_000003_000002 PERRY COMP COMMON POINT 0.103200004 0.149100004 2.982000075 2.832900072 2.980509075 0.147609004 $132,647

NEI2TX4973_000019_000053_000054 BRIDGEPORT 3.581899881 14.40159968 288.0319935 273.6303938 287.8879775 14.25758368 $1,373

NEI6094_09_09_09 CHEVRON USA INC/DELTA DUCK STN 1 0.15648 0.74844 14.9688 14.22036 14.9613156 0.7409556 $26,425

NEI6453_000001_000034_000024 EXXON MOBIL SARITA COMPRE 0.163299993 0.530999988 10.61999975 10.08899976 10.61468975 0.525689988 $37,246

NEI6453_000003_000032_000029 EXXON MOBIL SARITA COMPRE 1.089699984 3.414100023 68.28200046 64.86790044 68.24785946 3.379959023 $5,793

NEI6456_000042_000022_000052 KING RANCH PLANT 13.44029999 14.9337 298.6739999 283.7402999 298.5246629 14.784363 $1,324

NEI6456_000045_000019_000049 KING RANCH PLANT 6.767099857 29.83200002 596.6400003 566.8080003 596.3416803 29.53368002 $663

NEI6483_000034_000023_000061 KATY GAS PLANT 0.289799988 1.163800001 23.27600002 22.11220002 23.26436202 1.152162001 $16,994

NEI6509_000036_000015_000011 CANADIAN PLANT 0.062920008 0.318827224 6.37654448 6.057717256 6.373356208 0.315638952 $62,032

NEI7410_000079_000025_000022 SPRINGTOWN GAS PLANT 0.515999973 1.614399964 32.28799928 30.67359932 32.27185528 1.598255964 $12,251

NEI7421_000019_000015_000027 VIBORES COMPRESSOR STATION 9.137700081 19.29670012 385.9340024 366.6373023 385.7410354 19.10373312 $1,025

NEI7449_000031_000024_000029 BRAZORIA NATURAL GAS BOOSTER 0.0891261 0.4516183 9.032366 8.5807477 9.027849817 0.447102117 $43,793

NEI7694_000012_000042_000016 HEADLEE DEV GAS PLANT 0.082000002 0.182000001 3.640000029 3.458000027 3.638180029 0.180180001 $108,668

NEI7785_000002_000002_000002 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.23437998 0.556379999 $35,192

NEI7785_000006_000006_000006 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.23437998 0.556379999 $35,192

NEI7785_000007_000007_000007 OYSTER LAKE FACILITY 0.5 1.729999989 34.59999979 32.8699998 34.58269979 1.712699989 $11,432

NEI7787_000008_000006_000007 TRAWICK CTRL TREATING STN 2.468699932 3.285399925 65.7079985 62.42259857 65.6751445 3.252545926 $6,020

NEI7787_000010_000007_000007 TRAWICK CTRL TREATING STN 0.981700003 1.309000012 26.18000023 24.87100022 26.16691023 1.295910011 $15,109

NEI7787_000012_000008_000007 TRAWICK CTRL TREATING STN 1.052999973 1.380999973 27.61999946 26.23899949 27.60618946 1.367189973 $14,321

NEI7839_000003_000003_000003 TRAWICK WEST STATION 17.1480999 27.39659971 547.9319942 520.5353945 547.6580282 27.12263371 $722

NEI7998_000017_000024_000015 SONORA GAS PLANT 0.519999981 1.769999951 35.39999902 33.62999907 35.38229902 1.752299952 $11,174

NEIAL0530005_01_008_008 VINTAGE PETROLEUM INC 21.4 55.45 1109 1053.55 1108.4455 54.8955 $357

NEIAL0530007_01_016_016 Escambia Operating Company LLC 0.86 3.49 69.8 66.31 69.7651 3.4551 $5,667

NEIAL10190_01_016_016 Union Oil of California 0.57 1.07 21.4 20.33 21.3893 1.0593 $18,484

NEICA0592118_1_70001_00001H AERA ENERGY LLC 0.07436 0.263045249 5.260904981 4.997859732 5.258274528 0.260414797 $75,187

NEICA1115664_2_70018_00001H SENECA RESOURCES CORP. 0.2916 1.0007 20.014 19.0133 20.003993 0.990693 $19,764

NEICO0186_01_002_002 CALPINE NATURAL GAS COMPANY-MAMM CREEK 3.09 3.09 61.8 58.71 61.7691 3.0591 $6,401

NEICO0450156_01_001_001 WILLIAM PRODUCTION RMT - RIFLE STATION 2.4825 4.8775 97.55 92.6725 97.501225 4.828725 $4,055

NEICO0450156_01_002_002 WILLIAM PRODUCTION RMT - RIFLE STATION 2.4825 4.9675 99.35 94.3825 99.300325 4.917825 $3,981

NEICO1230048_01_017_017 KERR-MCGEE ROCKY MOUNTAIN CORP - HUDSON 0.306 7.536000139 150.7200028 143.1840026 150.6446428 7.460640138 $2,624

NEICO1230048_01_018_018 KERR-MCGEE ROCKY MOUNTAIN CORP - HUDSON 0.1925 0.1925 3.85 3.6575 3.848075 0.190575 $102,741

NEICO1230057_01_021_021 KERR-MCGEE FT LUPTON COMPRESSOR STATION 0.0975 0.0975 1.95 1.8525 1.949025 0.096525 $202,848

NEICO1230184_01_006_006 KERR-MCGEE FREDERICK CS 0.224 0.224 4.48 4.256 4.47776 0.22176 $88,293

Attachment 4, page 3 4/17/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEILA0026_12_12_12 ENERVEST OPERATING LLC/LEEVILLE CS 4.01542 9.21326 184.2652 175.05194 184.1730674 9.1211274 $2,147

NEILA0075_08_08_08 STONE ENERGY CORP/LAFITTE FIELD COMPRESSOR STATION TB #5 & CAMP 0.77444 1.44932 28.9864 27.53708 28.9719068 1.4348268 $13,646

NEILA0123_02_02_02 GULFPORT ENERGY CORP/W COTE BLANCHE BAY DEHY 0.54444 1.16432 23.2864 22.12208 23.2747568 1.1526768 $16,986

NEILA0130_02_02_02 ENERVEST WEST COTE 2.9545 6.384 127.68 121.296 127.61616 6.32016 $3,098

NEILA0450042_12_12_12 SOURCE PETROLEUM INC/FAUSSE PT CS 2 1.21096 1.88588 37.7176 35.83172 37.6987412 1.8670212 $10,487

NEILA0690006_49_49_49 EXCO RESOURCES INC/BLK LAKE GAS PROC PLNT 0.1075 0.1155 2.31 2.1945 2.308845 0.114345 $171,235

NEILA0750033_44_44_44 OCEAN ENERGY, INC/MAIN PASS 69 PLATFORM B 0.2322 1.1766 23.532 22.3554 23.520234 1.164834 $16,809

NEILA0750033_45_45_45 OCEAN ENERGY, INC/MAIN PASS 69 PLATFORM B 0.2322 1.1766 23.532 22.3554 23.520234 1.164834 $16,809

NEILA0770023_43_43_43 BP AMERICA PROD CO/MORGANZA CENTRAL TANK BATTERY #1 0.1425 0.436 8.72 8.284 8.71564 0.43164 $45,362

NEILA0770023_44_44_44 BP AMERICA PROD CO/MORGANZA CENTRAL TANK BATTERY #1 1.034 3.161 63.22 60.059 63.18839 3.12939 $6,257

NEILA1010013_21_21_21 CABOT OIL & GAS CORP/BELLE ISLE BAT #1 0.0825 0.1085 2.17 2.0615 2.168915 0.107415 $182,282

NEILA1010042_22_22_22 NEXEN PETROLEUM USA INC/EUGENE ISL BLK 18 FLD 2.9315 4.3415 86.83 82.4885 86.786585 4.298085 $4,555

NEILA1090032_06_06_06 HILCORP ENERGY CO/CAILLOU ISLAND WESTSIDE CS 0.061919999 0.313759997 6.275199944 5.961439947 6.272062344 0.310622397 $63,034

NEILA13789_17_17_17 SOURCE PETROLEUM INC/FORDOCHE CS 1 CF8 TB 18 0.61284 1.04 20.8 19.76 20.7896 1.0296 $19,017

NEIMI055B915_P01S01_EU0003_SV0002 MERIT ENERGY CO. - GRANT 29 0.14157 0.23975 4.795 4.55525 4.7926025 0.2373525 $82,493

NEIMIB5587_P02S01_EU0014_SV0001 MERIT ENERGY COMPANY. - MAYFIELD 23 0.08139 0.13786 2.7572 2.61934 2.7558214 0.1364814 $143,462

NEIMIB9135_P01S01_EU0015_FUG002 MERIT ENERGY CO. - BEAR LAKE 13 0.14157 0.23975 4.795 4.55525 4.7926025 0.2373525 $82,493

NEIMIB9136_P01S01_EU0016_FUG002 MERIT ENERGY CO. - BEAR LAKE 22 0.23713 0.40161 8.0322 7.63059 8.0281839 0.3975939 $49,246

NEIMIB9142_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - CHARLTON 12 0.06194 0.10491 2.0982 1.99329 2.0971509 0.1038609 $188,520

NEIMIB9160_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - MAPLE GROVE 16 0.13096 0.22179 4.4358 4.21401 4.4335821 0.2195721 $89,173

NEIMIN6015_P01S01_EU0004_FUG004 PARTELLO COMPRESSOR STATION 0.108 0.2345 4.69 4.4555 4.687655 0.232155 $84,340

NEIMIN6015_P01S01_EU0009_FUG009 PARTELLO COMPRESSOR STATION 0.16 0.3295 6.59 6.2605 6.586705 0.326205 $60,023

NEIMIN6466_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC. - ST. KALKASKA 1-10 2.37124 4.01602 80.3204 76.30438 80.2802398 3.9758598 $4,925

NEIMIN6470_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC - USA KALKASKA 1-30 2.37124 4.01602 80.3204 76.30438 80.2802398 3.9758598 $4,925

NEIOK2038_48539_14514_14547 DCP MIDSTREAM LP 0.84 6.69 133.8 127.11 133.7331 6.6231 $2,956

NEIOK2529_53558_20110_20271 ONEOK FIELD SVC 0.05575896 0.28254088 5.6508176 5.36827672 5.647992191 0.279715471 $69,999

NEITX067CG00_000011_000018_000006 MCLEOD GAS PLANT 0.100699998 0.124799999 2.495999988 2.371199989 2.494751988 0.123551999 $158,475

NEITX157312F_000002_000002_000004 THOMPSON COMPRESSOR STATION 3 0.291599989 5.447599872 108.9519974 103.5043976 108.8975214 5.393123873 $3,631

NEITX18630_000033_000032_000030 SALT CREEK FIELD GAS PLANT 0.914699972 3.677900046 73.55800092 69.88010088 73.52122192 3.641121046 $5,377

NEITX18630_000035_000033_000032 SALT CREEK FIELD GAS PLANT 1.050899982 4.107399896 82.14799792 78.04059802 82.10692392 4.066325897 $4,815

NEITX18630_000036_000032_000019 SALT CREEK FIELD GAS PLANT 0.09042642 0.45820726 9.1641452 8.70593794 9.159563127 0.453625187 $43,163

NEITX18630_000037_000033_000019 SALT CREEK FIELD GAS PLANT 0.168549336 0.854070408 17.08140816 16.22733775 17.07286746 0.845529704 $23,157

NEITX201972B_000001_000007_000007 NORTH MILTON 2.345499992 5.512599893 110.2519979 104.739398 110.1968719 5.457473894 $3,588

NEITX215294O_000012_000009_000014 MCALLEN RANCH CENTRAL FACILITY 0.200399995 0.693599997 13.87199994 13.17839994 13.86506394 0.686663997 $28,514

NEITX383004K_000011_000042_000013 MIDKIFF GAS PLANT 0.109999999 0.132999999 2.659999989 2.52699999 2.658669989 0.131669999 $148,704

NEITXRHX1519_000009_000002_000002 KATHLEEN THARP 2 0.114399999 0.405700001 8.114000019 7.708300018 8.109943019 0.401643001 $48,749

NEITXRLI0045_000002_000001_000001 TUFCO-FALLON DEL STA 1.220000029 1.63000004 32.6000008 30.97000076 32.5837008 1.61370004 $12,134

NEITXRPE0020_000001_000017_000020 PIKES PEAK PLANT 0.430000007 4.820000112 96.40000224 91.58000213 96.35180224 4.771800111 $4,103

NEITXRPE0042_000001_000018_000006 COYANOSA GAS PLANT 0.100000001 0.92 18.4 17.48 18.3908 0.9108 $21,497

NEITXRSQ0088_000002_000002_000002 JUNO COMPRESSOR STATION 0.600899994 1.345000016 26.90000031 25.5550003 26.88655031 1.331550015 $14,705

NEITXRUA0156_000012_000013_000013 INDIAN ROCK GAS PLANT 0.284000009 1.137000035 22.74000071 21.60300067 22.72863071 1.125630035 $17,395

Grand Total 328.2950767

Attachment 4, page 4 4/17/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

Calculation of Incremental Cost Effectiveness for Zero Emissions Dehydration Unit

w/o savings with savings

Natural gas price 4 $/Mscf Average Incremental ER = 3.50 tpy

Methane content of Natural Gas for Production 79% (reference PRO Fact Sheet 206) Annual Cost of Zero Emissions Dehy = $25,738 /yr

Methane emissions from Dehys 2640 tpy (Ref BID) Annual Cost of Condenser System = $18,192 /yr

HAP emissions from Dehys 8800 tpy (Ref BID) Incremental Annual Cost = $7,546 /yr

0.300 ton Methane/ton HAP Average ICE = 17,597 $/ton 17,524 $/ton

MACT floor level of control 95% Range of ICE = $138.87 $/ton (Min) $65.95 $/ton (Min)

Level of control for zero emissons dehy 99.9% $78,977 $/ton (Max) $78,904 $/ton (Max)

Number of Dehys = 92 92

Number less than $5,000/ton = 33 33

Percent less than $5,000/ton = 36% 36%

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Zero Emiss Dehy 

(w/o savings)

Incremental 

Methane ER 

from Dehy (tpy)

Incremental 

Methane ER 

from dehy 

(scf/day)

Natural Gas 

Savings 

(assume 

$4/Mscf)

ICE associated 

with Zero Emiss 

Dehy 

(w/savings)

CE Due to 

MACT 

Control

CE Due to 

Zero 

Emissions 

Dehydrator

NEI11191_000023_000022_000011 WQPUEBLO PLANT 0.850000024 5.523599997 110.4719999 104.9483999 110.3615279 5.413127997 $1,394.06 1.6239 213.5812 $394.72 $1,321.14 $173.34 $233 

NEI11211_000042_000026_000063 CONROE COMPRESSOR STATION 1.725800037 12.2191004 244.382008 232.1629076 244.137626 11.97471839 $630.18 3.5924 472.4763 $873.18 $557.26 $78.36 $105 

NEI12047_000011_000143_000127 WASKOM GAS PLANT 0.2368 0.2833 5.665999996 5.382699996 5.660333996 0.277634 $27,180.55 0.0833 10.9544 $20.24 $27,107.63 $3,379.65 $4,547 

NEI12503_000011_000043_000047 BENEDUM GAS PLANT 0.059999999 0.219999999 4.399999976 4.179999977 4.395599976 0.215599999 $35,001.13 0.0647 8.5067 $15.72 $34,928.21 $4,352.07 $5,855 

NEI12819_000001_000001_000001 PINEHURST COMPRESSOR 

STATION

0.663999975 0.985899983 19.71799966 18.73209967 19.69828166 0.966181983 $7,810.38 0.2899 38.1218 $70.45 $7,737.46 $971.15 $1,307 

NEI13085_000015_000030_000010 LAKE CREEK PLANT 0.162200004 0.247100005 4.942000101 4.694900096 4.937058101 0.242158005 $31,162.48 0.0726 9.5546 $17.66 $31,089.56 $3,874.77 $5,213 

NEI13271_000002_000035_000032 ALAZAN COMPRESSOR STATION 0.158000007 0.313200013 6.26400026 5.950800247 6.25773626 0.306936013 $24,585.72 0.0921 12.1105 $22.38 $24,512.81 $3,057.01 $4,113 

NEI13316_000011_000007_000007 WILLOW SPRINGS PLANT 0.07 0.499999985 9.999999702 9.499999717 9.989999702 0.489999985 $15,400.50 0.1470 19.3335 $35.73 $15,327.58 $1,914.91 $2,576 

NEI2CO045363_01_002_002 ENCANA - EAST MAMM CREEK 

CS

0.204999998 0.204999998 4.099999964 3.894999966 4.095899964 0.200899998 $37,562.19 0.0603 7.9267 $14.65 $37,489.27 $4,670.52 $6,284 

NEI2CO045363_01_003_003 ENCANA - EAST MAMM CREEK 

CS

0.204999998 0.204999998 4.099999964 3.894999966 4.095899964 0.200899998 $37,562.19 0.0603 7.9267 $14.65 $37,489.27 $4,670.52 $6,284 

NEI2CO045363_01_007_007 ENCANA - EAST MAMM CREEK 

CS

3.285 16.87 337.4 320.53 337.0626 16.5326 $456.45 4.9598 652.3128 $1,205.54 $383.53 $56.75 $76 

NEI2CO045365_01_033_029 WILLIAMS PROD RMT CORP - 

PARACHUTE

0.626 1.336 26.72 25.384 26.69328 1.30928 $5,763.66 0.3928 51.6592 $95.47 $5,690.74 $716.66 $964 

NEI2OK1747_55854_7026_7026 DCP MIDSTREAM LP 0.0547992 0.2776776 5.553552 5.2758744 5.547998448 0.272124048 $27,730.90 0.0816 10.7370 $19.84 $27,657.98 $3,448.09 $4,639 

NEI2TX1520_000013_000004_000012 HAMILL ESTATE COMPRESSOR 

STATION

0.132400006 0.428800014 8.576000277 8.147200263 8.567424277 0.420224014 $17,957.67 0.1261 16.5804 $30.64 $17,884.75 $2,232.87 $3,004 

NEI2TX1619_000041_000012_000014 TEAGUE GAS PLANT 0.059999999 0.129999997 2.599999942 2.469999945 2.597399942 0.127399997 $59,232.69 0.0382 5.0267 $9.29 $59,159.77 $7,365.05 $9,909 

NEI2TX20371_000008_000008_000008 WHELAN N COMP STATION 0.132799998 0.140999998 2.819999959 2.678999961 2.817179959 0.138179998 $54,611.70 0.0415 5.4521 $10.08 $54,538.78 $6,790.47 $9,136 

NEI2TX39139_000006_000002_000001 TOM O'CONNER COMPRESSOR 

STATION

0.162100002 0.631300005 12.6260001 11.9947001 12.6133741 0.618674005 $12,197.45 0.1856 24.4105 $45.11 $12,124.53 $1,516.64 $2,041 

NEI2TX39520_000005_000003_000001 BOA GAS TREATING PLANT 0.286799997 0.338699998 6.773999953 6.435299955 6.767225953 0.331925998 $22,734.72 0.0996 13.0965 $24.20 $22,661.80 $2,826.86 $3,803 

NEI2TX42343_000009_000003_000002 PERRY COMP COMMON POINT 0.103200004 0.149100004 2.982000075 2.832900072 2.979018075 0.146118004 $51,644.86 0.0438 5.7653 $10.65 $51,571.94 $6,421.57 $8,640 

NEI2TX4973_000019_000053_000054 BRIDGEPORT 3.581899881 14.40159968 288.0319935 273.6303938 287.7439615 14.11356768 $534.68 4.2341 556.8671 $1,029.15 $461.76 $66.48 $89 

NEI6094_09_09_09 CHEVRON USA INC/DELTA DUCK 

STN 1

0.15648 0.74844 14.9688 14.22036 14.9538312 0.7334712 $10,288.40 0.2200 28.9400 $53.48 $10,215.48 $1,279.27 $1,721 

NEI6453_000001_000034_000024 EXXON MOBIL SARITA COMPRE 0.163299993 0.530999988 10.61999975 10.08899976 10.60937975 0.520379988 $14,501.41 0.1561 20.5322 $37.95 $14,428.49 $1,803.12 $2,426 

NEI6453_000003_000032_000029 EXXON MOBIL SARITA COMPRE 1.089699984 3.414100023 68.28200046 64.86790044 68.21371846 3.345818023 $2,255.43 1.0037 132.0131 $243.97 $2,182.51 $280.44 $377 

NEI6456_000042_000022_000052 KING RANCH PLANT 13.44029999 14.9337 298.6739999 283.7402999 298.3753259 14.635026 $515.63 4.3905 577.4418 $1,067.17 $442.71 $64.11 $86 

NEI6456_000045_000019_000049 KING RANCH PLANT 6.767099857 29.83200002 596.6400003 566.8080003 596.0433603 29.23536002 $258.12 8.7706 1153.5149 $2,131.81 $185.20 $32.09 $43 

NEI6483_000034_000023_000061 KATY GAS PLANT 0.289799988 1.163800001 23.27600002 22.11220002 23.25272402 1.140524001 $6,616.47 0.3422 45.0007 $83.17 $6,543.55 $822.70 $1,107 

NEI6509_000036_000015_000011 CANADIAN PLANT 0.062920008 0.318827224 6.37654448 6.057717256 6.370167936 0.31245068 $24,151.79 0.0937 12.3281 $22.78 $24,078.87 $3,003.06 $4,040 

NEI7410_000079_000025_000022 SPRINGTOWN GAS PLANT 0.515999973 1.614399964 32.28799928 30.67359932 32.25571128 1.582111965 $4,769.73 0.4746 62.4241 $115.37 $4,696.81 $593.07 $798 

NEI7421_000019_000015_000027 VIBORES COMPRESSOR STATION 9.137700081 19.29670012 385.9340024 366.6373023 385.5480684 18.91076612 $399.04 5.6732 746.1461 $1,378.95 $326.13 $49.62 $67 

NEI7449_000031_000024_000029 BRAZORIA NATURAL GAS 

BOOSTER

0.0891261 0.4516183 9.032366 8.5807477 9.023333634 0.442585934 $17,050.35 0.1328 17.4627 $32.27 $16,977.43 $2,120.06 $2,852 

NEI7694_000012_000042_000016 HEADLEE DEV GAS PLANT 0.082000002 0.182000001 3.640000029 3.458000027 3.636360029 0.178360001 $42,309.06 0.0535 7.0374 $13.01 $42,236.14 $5,260.75 $7,078 

NEI7785_000002_000002_000002 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.22875998 0.550759999 $13,701.51 0.1652 21.7309 $40.16 $13,628.59 $1,703.66 $2,292 

NEI7785_000006_000006_000006 OYSTER LAKE FACILITY 0.166999996 0.561999999 11.23999998 10.67799998 11.22875998 0.550759999 $13,701.51 0.1652 21.7309 $40.16 $13,628.59 $1,703.66 $2,292 

NEI7785_000007_000007_000007 OYSTER LAKE FACILITY 0.5 1.729999989 34.59999979 32.8699998 34.56539979 1.695399989 $4,451.01 0.5086 66.8940 $123.63 $4,378.09 $553.44 $745 

NEI7787_000008_000006_000007 TRAWICK CTRL TREATING STN 2.468699932 3.285399925 65.7079985 62.42259857 65.6422905 3.219691926 $2,343.78 0.9659 127.0367 $234.78 $2,270.86 $291.43 $392 

NEI7787_000010_000007_000007 TRAWICK CTRL TREATING STN 0.981700003 1.309000012 26.18000023 24.87100022 26.15382023 1.282820011 $5,882.54 0.3848 50.6151 $93.54 $5,809.62 $731.44 $984 

NEI7787_000012_000008_000007 TRAWICK CTRL TREATING STN 1.052999973 1.380999973 27.61999946 26.23899949 27.59237946 1.353379974 $5,575.85 0.4060 53.3992 $98.69 $5,502.93 $693.31 $933 

NEI7839_000003_000003_000003 TRAWICK WEST STATION 17.1480999 27.39659971 547.9319942 520.5353945 547.3840622 26.84866772 $281.07 8.0546 1059.3452 $1,957.78 $208.15 $34.95 $47 

NEI7998_000017_000024_000015 SONORA GAS PLANT 0.519999981 1.769999951 35.39999902 33.62999907 35.36459902 1.734599952 $4,350.42 0.5204 68.4406 $126.49 $4,277.50 $540.94 $728 

NEIAL0530005_01_008_008 VINTAGE PETROLEUM INC 21.4 55.45 1109 1053.55 1107.891 54.341 $138.87 16.3023 2144.0869 $3,962.49 $65.95 $17.27 $23 

NEIAL0530007_01_016_016 Escambia Operating Company 

LLC

0.86 3.49 69.8 66.31 69.7302 3.4202 $2,206.38 1.0261 134.9479 $249.40 $2,133.46 $274.34 $369 

NEIAL10190_01_016_016 Union Oil of California 0.57 1.07 21.4 20.33 21.3786 1.0486 $7,196.49 0.3146 41.3737 $76.46 $7,123.58 $894.82 $1,204 

NEICA0592118_1_70001_00001H AERA ENERGY LLC 0.07436 0.263045249 5.260904981 4.997859732 5.255644076 0.257784344 $29,273.48 0.0773 10.1712 $18.80 $29,200.56 $3,639.89 $4,897 

NEICA1115664_2_70018_00001H SENECA RESOURCES CORP. 0.2916 1.0007 20.014 19.0133 19.993986 0.980686 $7,694.86 0.2942 38.6941 $71.51 $7,621.94 $956.79 $1,287 

NEICO0186_01_002_002 CALPINE NATURAL GAS 

COMPANY-MAMM CREEK

3.09 3.09 61.8 58.71 61.7382 3.0282 $2,491.99 0.9085 119.4811 $220.81 $2,419.07 $309.86 $417 

NEICO0450156_01_001_001 WILLIAM PRODUCTION RMT - 

RIFLE STATION

2.4825 4.8775 97.55 92.6725 97.45245 4.77995 $1,578.73 1.4340 188.5984 $348.55 $1,505.81 $196.30 $264 

NEICO0450156_01_002_002 WILLIAM PRODUCTION RMT - 

RIFLE STATION

2.4825 4.9675 99.35 94.3825 99.25065 4.86815 $1,550.13 1.4604 192.0785 $354.98 $1,477.21 $192.74 $259 

NEICO1230048_01_017_017 KERR-MCGEE ROCKY MOUNTAIN 

CORP - HUDSON

0.306 7.536000139 150.7200028 143.1840026 150.5692828 7.385280136 $1,021.80 2.2156 291.3948 $538.53 $948.88 $127.05 $171 

NEICO1230048_01_018_018 KERR-MCGEE ROCKY MOUNTAIN 

CORP - HUDSON

0.1925 0.1925 3.85 3.6575 3.84615 0.18865 $40,001.30 0.0566 7.4434 $13.76 $39,928.38 $4,973.80 $6,692 

Attachment 4, page 5 4/17/2012
ATTACHMENT 4

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Production

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Zero Emiss Dehy 

(w/o savings)

Incremental 

Methane ER 

from Dehy (tpy)

Incremental 

Methane ER 

from dehy 

(scf/day)

Natural Gas 

Savings 

(assume 

$4/Mscf)

ICE associated 

with Zero Emiss 

Dehy 

(w/savings)

CE Due to 

MACT 

Control

CE Due to 

Zero 

Emissions 

Dehydrator

NEICO1230057_01_021_021 KERR-MCGEE FT LUPTON 

COMPRESSOR STATION

0.0975 0.0975 1.95 1.8525 1.94805 0.09555 $78,976.92 0.0287 3.7700 $6.97 $78,904.00 $9,820.06 $13,212 

NEICO1230184_01_006_006 KERR-MCGEE FREDERICK CS 0.224 0.224 4.48 4.256 4.47552 0.21952 $34,376.11 0.0659 8.6614 $16.01 $34,303.19 $4,274.36 $5,751 

NEILA0026_12_12_12 ENERVEST OPERATING 

LLC/LEEVILLE CS

4.01542 9.21326 184.2652 175.05194 184.0809348 9.0289948 $835.78 2.7087 356.2494 $658.38 $762.86 $103.92 $140 

NEILA0075_08_08_08 STONE ENERGY CORP/LAFITTE 

FIELD COMPRESSOR STATION TB 

#5 & CAMP

0.77444 1.44932 28.9864 27.53708 28.9574136 1.4203336 $5,313.01 0.4261 56.0409 $103.57 $5,240.09 $660.62 $889 

NEILA0123_02_02_02 GULFPORT ENERGY CORP/W 

COTE BLANCHE BAY DEHY

0.54444 1.16432 23.2864 22.12208 23.2631136 1.1410336 $6,613.52 0.3423 45.0208 $83.20 $6,540.60 $822.33 $1,106 

NEILA0130_02_02_02 ENERVEST WEST COTE 2.9545 6.384 127.68 121.296 127.55232 6.25632 $1,206.18 1.8769 246.8503 $456.20 $1,133.26 $149.98 $202 

NEILA0450042_12_12_12 SOURCE PETROLEUM 

INC/FAUSSE PT CS 2

1.21096 1.88588 37.7176 35.83172 37.6798824 1.8481624 $4,083.11 0.5544 72.9214 $134.77 $4,010.19 $507.70 $683 

NEILA0690006_49_49_49 EXCO RESOURCES INC/BLK LAKE 

GAS PROC PLNT

0.1075 0.1155 2.31 2.1945 2.30769 0.11319 $66,668.83 0.0340 4.4660 $8.25 $66,595.91 $8,289.66 $11,153 

NEILA0750033_44_44_44 OCEAN ENERGY, INC/MAIN PASS 

69 PLATFORM B

0.2322 1.1766 23.532 22.3554 23.508468 1.153068 $6,544.49 0.3459 45.4956 $84.08 $6,471.57 $813.75 $1,095 

NEILA0750033_45_45_45 OCEAN ENERGY, INC/MAIN PASS 

69 PLATFORM B

0.2322 1.1766 23.532 22.3554 23.508468 1.153068 $6,544.49 0.3459 45.4956 $84.08 $6,471.57 $813.75 $1,095 

NEILA0770023_43_43_43 BP AMERICA PROD 

CO/MORGANZA CENTRAL TANK 

BATTERY #1

0.1425 0.436 8.72 8.284 8.71128 0.42728 $17,661.12 0.1282 16.8588 $31.16 $17,588.20 $2,196.00 $2,955 

NEILA0770023_44_44_44 BP AMERICA PROD 

CO/MORGANZA CENTRAL TANK 

BATTERY #1

1.034 3.161 63.22 60.059 63.15678 3.09778 $2,436.02 0.9293 122.2265 $225.89 $2,363.10 $302.90 $408 

NEILA1010013_21_21_21 CABOT OIL & GAS CORP/BELLE 

ISLE BAT #1

0.0825 0.1085 2.17 2.0615 2.16783 0.10633 $70,970.04 0.0319 4.1954 $7.75 $70,897.12 $8,824.48 $11,873 

NEILA1010042_22_22_22 NEXEN PETROLEUM USA 

INC/EUGENE ISL BLK 18 FLD

2.9315 4.3415 86.83 82.4885 86.74317 4.25467 $1,773.64 1.2764 167.8729 $310.25 $1,700.72 $220.54 $297 

NEILA1090032_06_06_06 HILCORP ENERGY CO/CAILLOU 

ISLAND WESTSIDE CS

0.061919999 0.313759997 6.275199944 5.961439947 6.268924744 0.307484797 $24,541.85 0.0922 12.1322 $22.42 $24,468.93 $3,051.56 $4,106 

NEILA13789_17_17_17 SOURCE PETROLEUM 

INC/FORDOCHE CS 1 CF8 TB 18

0.61284 1.04 20.8 19.76 20.7792 1.0192 $7,404.09 0.3058 40.2137 $74.32 $7,331.17 $920.63 $1,239 

NEIMI055B915_P01S01_EU0003_SV0002 MERIT ENERGY CO. - GRANT 29 0.14157 0.23975 4.795 4.55525 4.790205 0.234955 $32,117.83 0.0705 9.2704 $17.13 $32,044.91 $3,993.56 $5,373 

NEIMIB5587_P02S01_EU0014_SV0001 MERIT ENERGY COMPANY. - 

MAYFIELD 23

0.08139 0.13786 2.7572 2.61934 2.7544428 0.1351028 $55,855.57 0.0405 5.3306 $9.85 $55,782.65 $6,945.13 $9,344 

NEIMIB9135_P01S01_EU0015_FUG002 MERIT ENERGY CO. - BEAR LAKE 

13

0.14157 0.23975 4.795 4.55525 4.790205 0.234955 $32,117.83 0.0705 9.2704 $17.13 $32,044.91 $3,993.56 $5,373 

NEIMIB9136_P01S01_EU0016_FUG002 MERIT ENERGY CO. - BEAR LAKE 

22

0.23713 0.40161 8.0322 7.63059 8.0241678 0.3935778 $19,173.45 0.1181 15.5291 $28.70 $19,100.53 $2,384.04 $3,208 

NEIMIB9142_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - 

CHARLTON 12

0.06194 0.10491 2.0982 1.99329 2.0961018 0.1028118 $73,398.62 0.0308 4.0566 $7.50 $73,325.70 $9,126.45 $12,279 

NEIMIB9160_P01S01_EU0011_FUG003 MERIT ENERGY COMPANY - 

MAPLE GROVE 16

0.13096 0.22179 4.4358 4.21401 4.4313642 0.2173542 $34,718.65 0.0652 8.5760 $15.85 $34,645.73 $4,316.95 $5,808 

NEIMIN6015_P01S01_EU0004_FUG004 PARTELLO COMPRESSOR 

STATION

0.108 0.2345 4.69 4.4555 4.68531 0.22981 $32,836.88 0.0689 9.0674 $16.76 $32,763.97 $4,082.97 $5,493 

NEIMIN6015_P01S01_EU0009_FUG009 PARTELLO COMPRESSOR 

STATION

0.16 0.3295 6.59 6.2605 6.58341 0.32291 $23,369.50 0.0969 12.7408 $23.55 $23,296.58 $2,905.78 $3,910 

NEIMIN6466_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC. - 

ST. KALKASKA 1-10

2.37124 4.01602 80.3204 76.30438 80.2400796 3.9356996 $1,917.38 1.1807 155.2876 $286.99 $1,844.46 $238.41 $321 

NEIMIN6470_P02S01_EU0003_SV0003 QUICKSILVER RESOURCES INC - 

USA KALKASKA 1-30

2.37124 4.01602 80.3204 76.30438 80.2400796 3.9356996 $1,917.38 1.1807 155.2876 $286.99 $1,844.46 $238.41 $321 

NEIOK2038_48539_14514_14547 DCP MIDSTREAM LP 0.84 6.69 133.8 127.11 133.6662 6.5562 $1,151.01 1.9669 258.6824 $478.07 $1,078.09 $143.12 $193 

NEIOK2529_53558_20110_20271 ONEOK FIELD SVC 0.05575896 0.28254088 5.6508176 5.36827672 5.645166782 0.276890062 $27,253.58 0.0831 10.9250 $20.19 $27,180.66 $3,388.73 $4,559 

NEITX067CG00_000011_000018_000006 MCLEOD GAS PLANT 0.100699998 0.124799999 2.495999988 2.371199989 2.493503988 0.122303999 $61,700.72 0.0367 4.8256 $8.92 $61,627.80 $7,671.92 $10,322 

NEITX157312F_000002_000002_000004 THOMPSON COMPRESSOR 

STATION 3

0.291599989 5.447599872 108.9519974 103.5043976 108.8430454 5.338647875 $1,413.51 1.6016 210.6425 $389.29 $1,340.59 $175.76 $236 

NEITX18630_000033_000032_000030 SALT CREEK FIELD GAS PLANT 0.914699972 3.677900046 73.55800092 69.88010088 73.48444292 3.604342045 $2,093.65 1.0813 142.2135 $262.82 $2,020.73 $260.33 $350 

NEITX18630_000035_000033_000032 SALT CREEK FIELD GAS PLANT 1.050899982 4.107399896 82.14799792 78.04059802 82.06584992 4.025251898 $1,874.73 1.2076 158.8210 $293.52 $1,801.81 $233.11 $314 

NEITX18630_000036_000032_000019 SALT CREEK FIELD GAS PLANT 0.09042642 0.45820726 9.1641452 8.70593794 9.154981055 0.449043115 $16,805.17 0.1347 17.7175 $32.74 $16,732.25 $2,089.57 $2,811 

NEITX18630_000037_000033_000019 SALT CREEK FIELD GAS PLANT 0.168549336 0.854070408 17.08140816 16.22733775 17.06432675 0.836989 $9,015.94 0.2511 33.0244 $61.03 $8,943.02 $1,121.05 $1,508 

NEITX201972B_000001_000007_000007 NORTH MILTON 2.345499992 5.512599893 110.2519979 104.739398 110.1417459 5.402347895 $1,396.85 1.6207 213.1559 $393.93 $1,323.93 $173.69 $234 

NEITX215294O_000012_000009_000014 MCALLEN RANCH CENTRAL 

FACILITY

0.200399995 0.693599997 13.87199994 13.17839994 13.85812794 0.679727997 $11,101.86 0.2039 26.8195 $49.57 $11,028.94 $1,380.42 $1,857 

NEITX383004K_000011_000042_000013 MIDKIFF GAS PLANT 0.109999999 0.132999999 2.659999989 2.52699999 2.657339989 0.130339999 $57,896.61 0.0391 5.1427 $9.50 $57,823.69 $7,198.92 $9,686 

NEITXRHX1519_000009_000002_000002 KATHLEEN THARP 2 0.114399999 0.405700001 8.114000019 7.708300018 8.105886019 0.397586001 $18,980.16 0.1193 15.6872 $28.99 $18,907.24 $2,360.01 $3,175 

NEITXRLI0045_000002_000001_000001 TUFCO-FALLON DEL STA 1.220000029 1.63000004 32.6000008 30.97000076 32.5674008 1.597400039 $4,724.08 0.4792 63.0273 $116.48 $4,651.16 $587.40 $790 

NEITXRPE0020_000001_000017_000020 PIKES PEAK PLANT 0.430000007 4.820000112 96.40000224 91.58000213 96.30360224 4.72360011 $1,597.56 1.4171 186.3751 $344.44 $1,524.64 $198.64 $267 

NEITXRPE0042_000001_000018_000006 COYANOSA GAS PLANT 0.100000001 0.92 18.4 17.48 18.3816 0.9016 $8,369.84 0.2705 35.5737 $65.74 $8,296.92 $1,040.71 $1,400 

NEITXRSQ0088_000002_000002_000002 JUNO COMPRESSOR STATION 0.600899994 1.345000016 26.90000031 25.5550003 26.87310031 1.318100015 $5,725.09 0.3954 52.0072 $96.11 $5,652.17 $711.86 $958 

NEITXRUA0156_000012_000013_000013 INDIAN ROCK GAS PLANT 0.284000009 1.137000035 22.74000071 21.60300067 22.71726071 1.114260035 $6,772.43 0.3343 43.9644 $81.25 $6,699.51 $842.09 $1,133 

Grand Total 328.2950767

Attachment 4, page 6 4/17/2012
ATTACHMENT 5

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Transmission and Storage

Calculation of Incremental Cost Effectiveness for Emission Reduction of 98 percent.

Average Incremental ER 1.25 tpy

Annual Cost of Combustor = $19,580 /yr

MACT floor level of control 95% Average ICE = 46,914 $/ton

Above the floor level of control 98.00% Range of ICE = $2,784 $/ton (Min)

$208,336 $/ton (Max)

Number of Dehys = 15

Number less than $5,000/ton = 1

Percent less than $5,000/ton = 7%

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEI11118_000003_000010_000011 EAST VILLAGE MILLS 0.098700002 0.804900004 16.09800007 15.29310007 16.08190207 0.788802004 $24,822.29

NEI12421_000019_000021_000018 STATION 581 0.061799999 0.095899999 1.91799999 1.82209999 1.91608199 0.093982 $208,336.40

NEI12421_000020_000020_000018 STATION 581 0.324699998 0.503999998 10.07999996 9.575999959 10.06991996 0.493919998 $39,641.79

NEI12805_000004_000009_000009 MITCHELL PLANT 0.469999999 2.96999998 59.3999996 56.42999962 59.3405996 2.910599981 $6,727.09

NEI2TX21310_000002_000001_000023 TRI CITIES STA 0.0911 1.259500044 25.19000089 23.93050084 25.16481089 1.234310044 $15,863.01

NEI6482_000004_000027_000026 KELSEY STATION 3.883599997 7.175600052 143.512001 136.336401 143.368489 7.032088051 $2,784.36

NEILA1010014_13_13_13 GULF SOUTH PIPELINE CO/BURNS POINT TREATING FACILITY 0.139319998 0.705959994 14.11919987 13.41323988 14.10508068 0.691840794 $28,301.12

NEILA13384_16_16_16 ACADIAN GAS PIPELINE/GRAND BAYOU STORAGE FACILITY 0.1395 0.36 7.2 6.84 7.1928 0.3528 $55,498.50

NEILA13384_17_17_17 ACADIAN GAS PIPELINE/GRAND BAYOU STORAGE FACILITY 0.1215 0.314 6.28 5.966 6.27372 0.30772 $63,628.86

NEIOK1056_39684_4263_4263 ANADARKO GATHERING CO 0.06894792 0.34937176 6.9874352 6.63806344 6.980447765 0.342384325 $57,186.82

NEIOK2226_49852_4100_4100 ONEOK GAS STORAGE LLC 0.076 0.81 16.2 15.39 16.1838 0.7938 $24,666.00

NEIOK2372_140878_4231_4231 PANHANDLE EASTERN PIPELINE CO 0.2715192 1.3758376 27.516752 26.1409144 27.48923525 1.348320848 $14,521.67

NEIOK401491548_53873_4682_4682 ENOGEX GAS GATHERING LLC 0.195729117 0.991795351 19.83590702 18.84411167 19.81607112 0.971959444 $20,144.74

NEITX065094I_000002_000013_000013 BURNETT MAIN COMPRESSOR 0.360599995 1.195100009 23.90200019 22.70690018 23.87809819 1.171198009 $16,717.81

NEITXRJE0157_000003_000003_000002 STATION 344 0.135800004 0.160000004 3.200000087 3.040000082 3.196800087 0.156800004 $124,871.63

Grand Total 19.0719648

Attachment 5, page 1 4/17/2012
ATTACHMENT 5

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Transmission and Storage

Calculation of Incremental Cost Effectiveness for Emission Reduction of 99 percent.

Average Incremental ER 1.26 tpy

Annual Cost of Combustor = $19,580 /yr

MACT floor level of control 95% Average ICE = 46,440 $/ton

Above the floor level of control 99.00% Range of ICE = $2,756 $/ton (Min)

$206,232 $/ton (Max)

Number of Dehys = 15

Number less than $5,000/ton = 1

Percent less than $5,000/ton = 7%

ID FACILITY_NAME BENZENE_EMIS Sum of Total_HAP_emis

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due to 

Additional Control

Incremental 

Emission Reduction

ICE associated with 

Combustion Device

NEI11118_000003_000010_000011 EAST VILLAGE MILLS 0.098700002 0.804900004 16.09800007 15.29310007 16.08995107 0.796851004 $24,571.56

NEI12421_000019_000021_000018 STATION 581 0.061799999 0.095899999 1.91799999 1.82209999 1.91704099 0.094940999 $206,231.99

NEI12421_000020_000020_000018 STATION 581 0.324699998 0.503999998 10.07999996 9.575999959 10.07495996 0.498959998 $39,241.37

NEI12805_000004_000009_000009 MITCHELL PLANT 0.469999999 2.96999998 59.3999996 56.42999962 59.3702996 2.94029998 $6,659.14

NEI2TX21310_000002_000001_000023 TRI CITIES STA 0.0911 1.259500044 25.19000089 23.93050084 25.17740589 1.246905044 $15,702.78

NEI6482_000004_000027_000026 KELSEY STATION 3.883599997 7.175600052 143.512001 136.336401 143.440245 7.103844051 $2,756.24

NEILA1010014_13_13_13 GULF SOUTH PIPELINE CO/BURNS POINT TREATING FACILITY 0.139319998 0.705959994 14.11919987 13.41323988 14.11214028 0.698900394 $28,015.25

NEILA13384_16_16_16 ACADIAN GAS PIPELINE/GRAND BAYOU STORAGE FACILITY 0.1395 0.36 7.2 6.84 7.1964 0.3564 $54,937.91

NEILA13384_17_17_17 ACADIAN GAS PIPELINE/GRAND BAYOU STORAGE FACILITY 0.1215 0.314 6.28 5.966 6.27686 0.31086 $62,986.14

NEIOK1056_39684_4263_4263 ANADARKO GATHERING CO 0.06894792 0.34937176 6.9874352 6.63806344 6.983941482 0.345878042 $56,609.18

NEIOK2226_49852_4100_4100 ONEOK GAS STORAGE LLC 0.076 0.81 16.2 15.39 16.1919 0.8019 $24,416.85

NEIOK2372_140878_4231_4231 PANHANDLE EASTERN PIPELINE CO 0.2715192 1.3758376 27.516752 26.1409144 27.50299362 1.362079224 $14,374.99

NEIOK401491548_53873_4682_4682 ENOGEX GAS GATHERING LLC 0.195729117 0.991795351 19.83590702 18.84411167 19.82598907 0.981877398 $19,941.26

NEITX065094I_000002_000013_000013 BURNETT MAIN COMPRESSOR 0.360599995 1.195100009 23.90200019 22.70690018 23.89004919 1.183149009 $16,548.95

NEITXRJE0157_000003_000003_000002 STATION 344 0.135800004 0.160000004 3.200000087 3.040000082 3.198400087 0.158400004 $123,610.30

Grand Total 19.0719648

Attachment 5, page 2 4/17/2012
ATTACHMENT 5

2005 NEI Database - Incremental Cost Effectiveness for Large Dehydration Units - Transmission and Storage

Calculation of Incremental Cost Effectiveness for Zero Emissions Dehydration Unit

w/o savings with savings

Natural gas price 4 $/Mscf Average Incremental ER = 1.25 tpy

Methane content of Natural Gas for Production 94% Annual Cost of Zero Emissions Dehy = $65,825 /yr

Methane emissions from Dehys 2640 tpy (Ref BID) Annual Cost of Condenser System = $18,192 /yr

HAP emissions from Dehys 8800 tpy (Ref BID) Incremental Annual Cost = $47,633 /yr

0.300 ton Methane/ton HAP Average ICE = 114,131 $/ton 114,070 $/ton

MACT floor level of control 95% Range of ICE = $6,774 $/ton (Min) $6,712 $/ton (Min)

Level of control for zero emissons dehy 99.9% $506,834 $/ton (Max) $506,773 $/ton (Max)

Number of Dehys = 15 15

Number less than $5,000/ton = 0 0

Percent less than $5,000/ton = 0% 0%

ID FACILITY_NAME BENZENE_EMIS Total_HAP_EMIS

Uncontrolled 

Emissions

MACT 

Emission 

Reduction

Emission 

Reduction due 

to Additional 

Control

Incremental 

Emission 

Reduction

ICE associated 

with Zero Emiss 

Dehy (w/o 

savings)

Incremental 

Methane ER 

from Dehy 

(tpy)

Incremental 

Methane ER 

from dehy 

(scf/day)

Natural Gas 

Savings 

(assume 

$4/Mscf)

ICE associated 

with Zero Emiss 

Dehy 

(w/savings)

NEI11118_000003_000010_000011 EAST VILLAGE MILLS 0.098700002 0.804900004 16.09800007 15.29310007 16.08190207 0.788802004 $60,386.90 0.2366 31.1231 $48.34 $60,325.62 

NEI12421_000019_000021_000018 STATION 581 0.061799999 0.095899999 1.91799999 1.82209999 1.91608199 0.093982 $506,834.37 0.0282 3.7082 $5.76 $506,773.08 

NEI12421_000020_000020_000018 STATION 581 0.324699998 0.503999998 10.07999996 9.575999959 10.06991996 0.493919998 $96,439.32 0.1482 19.4882 $30.27 $96,378.03 

NEI12805_000004_000009_000009 MITCHELL PLANT 0.469999999 2.96999998 59.3999996 56.42999962 59.3405996 2.910599981 $16,365.46 0.8732 114.8411 $178.37 $16,304.18 

NEI2TX21310_000002_000001_000023 TRI CITIES STA 0.0911 1.259500044 25.19000089 23.93050084 25.16481089 1.234310044 $38,591.04 0.3703 48.7011 $75.64 $38,529.76 

NEI6482_000004_000027_000026 KELSEY STATION 3.883599997 7.175600052 143.512001 136.336401 143.368489 7.032088051 $6,773.71 2.1096 277.4592 $430.95 $6,712.42 

NEILA1010014_13_13_13 GULF SOUTH PIPELINE CO/BURNS 

POINT TREATING FACILITY

0.139319998 0.705959994 14.11919987 13.41323988 14.10508068 0.691840794 $68,850.10 0.2076 27.2974 $42.40 $68,788.82 

NEILA13384_16_16_16 ACADIAN GAS PIPELINE/GRAND 

BAYOU STORAGE FACILITY

0.1395 0.36 7.2 6.84 7.1928 0.3528 $135,015.04 0.1058 13.9201 $21.62 $134,953.76 

NEILA13384_17_17_17 ACADIAN GAS PIPELINE/GRAND 

BAYOU STORAGE FACILITY

0.1215 0.314 6.28 5.966 6.27372 0.30772 $154,794.32 0.0923 12.1414 $18.86 $154,733.03 

NEIOK1056_39684_4263_4263 ANADARKO GATHERING CO 0.06894792 0.34937176 6.9874352 6.63806344 6.980447765 0.342384325 $139,122.34 0.1027 13.5092 $20.98 $139,061.05 

NEIOK2226_49852_4100_4100 ONEOK GAS STORAGE LLC 0.076 0.81 16.2 15.39 16.1838 0.7938 $60,006.69 0.2381 31.3203 $48.65 $59,945.40 

NEIOK2372_140878_4231_4231 PANHANDLE EASTERN PIPELINE CO 0.2715192 1.3758376 27.516752 26.1409144 27.48923525 1.348320848 $35,327.87 0.4045 53.1996 $82.63 $35,266.59 

NEIOK401491548_53873_4682_4682 ENOGEX GAS GATHERING LLC 0.195729117 0.991795351 19.83590702 18.84411167 19.81607112 0.971959444 $49,007.50 0.2916 38.3498 $59.56 $48,946.22 

NEITX065094I_000002_000013_000013 BURNETT MAIN COMPRESSOR 0.360599995 1.195100009 23.90200019 22.70690018 23.87809819 1.171198009 $40,670.58 0.3514 46.2110 $71.77 $40,609.30 

NEITXRJE0157_000003_000003_000002 STATION 344 0.135800004 0.160000004 3.200000087 3.040000082 3.196800087 0.156800004 $303,783.84 0.0470 6.1867 $9.61 $303,722.55 

Grand Total

Attachment 5, page 3 4/17/2012
ATTACHMENT 6

Incremental Cost Effectiveness - Storage Vessels with the Potential for Flash Emissions

0.95 Assumed that all controlled sources are achieving emission reduction of 95%

Annual Cost of VRU (assumed to achieve 95 percent control = $18,983 /yr

0.95 Emission Reduction (1999 MACT) Annual Cost of Combustor (assumed to include piping operating w/no detect emiss) $19,580 /yr

0.98 Improved emission reduction Incremental Annual Cost = $597 /yr

Average ICE = $81,316,294 $/ton

Range of ICE = $66 $/ton (Min)

$11,701,745,057 $/ton (Max)

Number of Facilities = 174

Number less than $5,000/ton = 34

Percent less than $5,000/ton = 20%

Values Existing Sources

NTI_SITE_ID FACILITY_NAME CONTROL_STATUS Count of Expr1 Sum of SumOfEMISSIONS_TPY Control Status Control Efficiency

Uncontrolled 

Emissions (tpy)

Emission 

Reduction 

at 95%

Emission 

Reduction 

at 98% Incremental ER

Number of 

Control 

Devices 

Required Incremental TAC Incremental CE

NEI11771 NORTH POINT BOLIVAR FIELD CONTROLLED 1 0.13136496 Controlled 0.95 2.6272992 2.4959342 2.5747532 0.078818976 1 $597 $7,572

NEI11924 MORGAN BLUFF FIELD CONTROLLED 9 0.141282162 Controlled 0.95 2.825643247 2.6843611 2.7691304 0.084769297 3 $1,790 $21,120

NEI11929 OYSTER BAYOU CONTROLLED 2 0.058241856 Controlled 0.95 1.16483712 1.1065953 1.1415404 0.034945114 1 $597 $17,078

NEI12150 VIDOR PRODUCTION FACILITY CONTROLLED 5 0.1384848 Controlled 0.95 2.769696 2.6312112 2.7143021 0.08309088 2 $1,194 $14,365

NEI12270 HANKAMER CONTROLLED 4 0.0461616 Controlled 0.95 0.923232 0.8770704 0.9047674 0.02769696 1 $597 $21,547

NEI12281 WEST CLEAR LAKE PEAKING CONTROLLED 4 0.010108608 Controlled 0.95 0.20217216 0.1920636 0.1981287 0.006065165 1 $597 $98,396

NEI12472 JOURDANTON FACILITY CONTROLLED 2 6.2592E-05 Controlled 0.95 0.00125184 0.0011892 0.0012268 3.75552E-05 1 $597 $15,890,982

NEI12862 LAKE CREEK T B 3 CONTROLLED 3 0.286037616 Controlled 0.95 5.72075232 5.4347147 5.6063373 0.17162257 1 $597 $3,477

NEI12914 LAKE CREEK TANK BATT 4 CONTROLLED 5 0.418959552 Controlled 0.95 8.37919104 7.9602315 8.2116072 0.251375731 2 $1,194 $4,748

NEI13271 ALAZAN COMPRESSOR STATION CONTROLLED 1 0.153405168 Controlled 0.95 3.06810336 2.9146982 3.0067413 0.092043101 1 $597 $6,484

NEI19944 M.H. WHITTIER CORPORATION CONTROLLED 11 0.022054262 Controlled 0.95 0.441085237 0.419031 0.4322635 0.013232557 3 $1,790 $135,300

NEI19963 UNOCAL OIL AND GAS DIVISION CONTROLLED 15 0.001377811 Controlled 0.95 0.027556225 0.0261784 0.0270051 0.000826687 4 $2,387 $2,887,619

NEI20033 ANCORA VERDE CORPORATION CONTROLLED 11 0.000365711 Controlled 0.95 0.00731421 0.0069485 0.0071679 0.000219426 3 $1,790 $8,159,309

NEI20053 CHALLENGER MINERALS INC CONTROLLED 27 0.011399621 Controlled 0.95 0.227992429 0.2165928 0.2234326 0.006839773 7 $4,178 $610,769

NEI20158 SHELL BAKERSFIELD TANK FARM CONTROLLED 3 0.038081112 Controlled 0.95 0.76162224 0.7235411 0.7463898 0.022848667 1 $597 $26,119

NEI20384 BREA CANON OIL COMPANY INC CONTROLLED 8 0.01882688 Controlled 0.95 0.3765376 0.3577107 0.3690068 0.011296128 2 $1,194 $105,663

NEI21031 MOBIL EXPLORATION & PRODUCING CONTROLLED 1 4.4855 Controlled 0.95 89.71 85.2245 87.9158 2.6913 1 $597 $222

NEI21164 PLACERITA OIL CO INC CONTROLLED 2 0.010631385 Controlled 0.95 0.2126277 0.2019963 0.2083751 0.006378831 1 $597 $93,558

NEI21389 TEXACO EXP & PROD INC;ALISO CY CONTROLLED 2 0.00422565 Controlled 0.95 0.084513 0.0802873 0.0828227 0.00253539 1 $597 $235,384

NEI21391 TEXACO EXPLORATION AND PRODUCT CONTROLLED 1 0.0003685 Controlled 0.95 0.00737 0.0070015 0.0072226 0.0002211 1 $597 $2,699,181

NEI21835 LONG BEACH OIL DEVELOPMENT CO CONTROLLED 1 0.0001 Controlled 0.95 0.002 0.0019 0.00196 6E-05 1 $597 $9,946,483

NEI22005 BREITBURN ENERGY CORP CONTROLLED 8 0.02192 Controlled 0.95 0.4384 0.41648 0.429632 0.013152 2 $1,194 $90,753

NEI22281 TEXACO EXPLORATION & PROD INC, CONTROLLED 2 0.00008735 Controlled 0.95 0.001747 0.0016597 0.0017121 5.241E-05 1 $597 $11,386,930

NEI23759 UNOCAL OIL AND GAS DIVISION CONTROLLED 5 1.6429E-06 Controlled 0.95 0.000032858 3.122E-05 3.22E-05 9.8574E-07 2 $1,194 $1,210,844,640

NEI25034 PATRIOT RESOURCES LLC CONTROLLED 1 6.92424E-05 Controlled 0.95 0.001384848 0.0013156 0.0013572 4.15454E-05 1 $597 $14,364,729

NEI25981 BERRY PETROLEUM COMPANY CONTROLLED 7 0.000220523 Controlled 0.95 0.004410466 0.0041899 0.0043223 0.000132314 2 $1,194 $9,020,801

NEI25997 PLAINS EXPLORATION & PRODUCTION COMPANY CONTROLLED 26 0.015864473 Controlled 0.95 0.317289466 0.301425 0.3109437 0.009518684 7 $4,178 $438,876

NEI26007 GEO PETROLEUM INC CONTROLLED 12 0.26109545 Controlled 0.95 5.221909 4.9608136 5.1174708 0.15665727 3 $1,790 $11,429

NEI26015 VAQUERO ENERGY INC. CONTROLLED 6 0.0001475 Controlled 0.95 0.00295 0.0028025 0.002891 0.0000885 2 $1,194 $13,486,757

NEI26021 JORO INC. CONTROLLED 2 0.000192371 Controlled 0.95 0.00384741 0.003655 0.0037705 0.000115422 1 $597 $5,170,483

NEI26023 LA CONCHITA OIL & GAS PLANT CONTROLLED 2 0.008705 Controlled 0.95 0.1741 0.165395 0.170618 0.005223 1 $597 $114,262

NEI26031 MIRADA PETROLEUM INC. CONTROLLED 9 0.00121465 Controlled 0.95 0.024293 0.0230784 0.0238071 0.00072879 3 $1,790 $2,456,629

NEI26096 THE TERMO COMPANY CONTROLLED 10 0.001033854 Controlled 0.95 0.02067707 0.0196432 0.0202635 0.000620312 3 $1,790 $2,886,236

NEI26101 TENBY INC. CONTROLLED 27 0.149152588 Controlled 0.95 2.983051751 2.8338992 2.9233907 0.089491553 7 $4,178 $46,681

NEI26117 VINTAGE PETROLEUM CONTROLLED 28 0.000120012 Controlled 0.95 0.002400248 0.0022802 0.0023522 7.20074E-05 7 $4,178 $58,015,169

NEI26118 VINTAGE PETROLEUM, INC. CONTROLLED 7 0.026050113 Controlled 0.95 0.52100225 0.4949521 0.5105822 0.015630068 2 $1,194 $76,364

NEI2CA114922 MAGNESS PETROLEUM COMPANY CONTROLLED 1 0.000000085 Controlled 0.95 0.0000017 1.615E-06 1.666E-06 0.000000051 1 $597 $11,701,745,057

NEI2CA251073 HALLADOR - SOUTH CUYAMA CONTROLLED 1 0.00178 Controlled 0.95 0.0356 0.03382 0.034888 0.001068 1 $597 $558,791

NEI2CA255008 GTC CONTROLLED 1 0.00228 Controlled 0.95 0.0456 0.04332 0.044688 0.001368 1 $597 $436,249

NEI2CA715272 CHEVRON U.S.A. CONTROLLED 1 0.0007655 Controlled 0.95 0.01531 0.0145445 0.0150038 0.0004593 1 $597 $1,299,345

NEI2CA800330 THUMS LONG BEACH CO CONTROLLED 1 3.7835E-06 Controlled 0.95 7.567E-05 7.189E-05 7.416E-05 2.2701E-06 1 $597 $262,891,061

NEI2CO045367 ENCANA OIL & GAS - HUNTER MESA CONTROLLED 1 1.164064 Controlled 0.95 23.28128 22.117216 22.815654 0.6984384 1 $597 $854

NEI2OK1747 DCP MIDSTREAM LP CONTROLLED 4 1.6164384 Controlled 0.95 32.328768 30.71233 31.682193 0.96986304 1 $597 $615

NEI2TX07186 UMBRELLA POINT--TRINITY BAY CONTROLLED 4 0.008197072 Controlled 0.95 0.163941442 0.1557444 0.1606626 0.004918243 1 $597 $121,342

NEI2TX07195 JACKSON HEIRS #1 PRODUCTION FACILITY CONTROLLED 6 0.327137088 Controlled 0.95 6.54274176 6.2156047 6.4118869 0.196282253 2 $1,194 $6,081

NEI2TX1619 TEAGUE GAS PLANT CONTROLLED 1 0.0046944 Controlled 0.95 0.093888 0.0891936 0.0920102 0.00281664 1 $597 $211,880

NEI2TX20353 JONESVILLE PLANT CONTROLLED 1 0.804510624 Controlled 0.95 16.09021248 15.285702 15.768408 0.482706374 1 $597 $1,236

NEI6453 EXXON MOBIL SARITA COMPRE CONTROLLED 3 0.027916032 Controlled 0.95 0.55832064 0.5304046 0.5471542 0.016749619 1 $597 $35,630

NEI6456 KING RANCH PLANT CONTROLLED 1 0.015311568 Controlled 0.95 0.30623136 0.2909198 0.3001067 0.009186941 1 $597 $64,961

NEI6458 WILCOX GAS PLANT CONTROLLED 2 1.5147264 Controlled 0.95 30.294528 28.779802 29.688637 0.90883584 1 $597 $657

NEI6602 WILLARD CO2 SEPARATION PLANT CONTROLLED 5 0.090797118 Controlled 0.95 1.815942364 1.7251452 1.7796235 0.054478271 2 $1,194 $21,909

NEI6948 HUMBLE COMMON STORAGE CONTROLLED 3 0.036819744 Controlled 0.95 0.73639488 0.6995751 0.721667 0.022091846 1 $597 $27,014

NEI7421 VIBORES COMPRESSOR STATION CONTROLLED 2 0.016062672 Controlled 0.95 0.32125344 0.3051908 0.3148284 0.009637603 1 $597 $61,923

NEI7703 THREE RIVERS PLANT CONTROLLED 2 1.279999981 Controlled 0.95 25.59999961 24.32 25.088 0.767999988 1 $597 $777

NEI7787 TRAWICK CTRL TREATING STN CONTROLLED 4 0.184896768 Controlled 0.95 3.69793536 3.5130386 3.6239767 0.110938061 1 $597 $5,379

NEI8007 HAWKINS GAS PLANT CONTROLLED 2 0.006900768 Controlled 0.95 0.13801536 0.1311146 0.1352551 0.004140461 1 $597 $144,136

NEIAL0530007 Escambia Operating Company LLC CONTROLLED 1 1.76 Controlled 0.95 35.2 33.44 34.496 1.056 1 $597 $565

NEICA019869 TEXACO CONTROLLED 1 0.0765481 Controlled 0.95 1.530962 1.4544139 1.5003428 0.04592886 1 $597 $12,994

NEICA019877 SANTA FE ENERGY RESOURCES INC. CONTROLLED 52 0.001707582 Controlled 0.95 0.034151645 0.0324441 0.0334686 0.001024549 13 $7,758 $7,572,360

NEICA0290178 NAVAL PETROLEUM RESERVE #1 CONTROLLED 736 0.007279416 Controlled 0.95 0.145588325 0.1383089 0.1426766 0.00436765 184 $109,809 $25,141,479

NEICA0291000 CONOCO INC., RIO VIEJO LEASE CONTROLLED 8 7.70526E-05 Controlled 0.95 0.001541051 0.001464 0.0015102 4.62315E-05 2 $1,194 $25,817,402

NEICA0291005 PHILLIPS PETROLEUM COMPANY CONTROLLED 20 0.020942682 Controlled 0.95 0.418853635 0.397911 0.4104766 0.012565609 5 $2,984 $237,469

NEICA0291007 DOLE ENTERPRISES CONTROLLED 2 0.091963685 Controlled 0.95 1.83927369 1.74731 1.8024882 0.055178211 1 $597 $10,816

NEICA0291018 VICTORY OIL COMPANY CONTROLLED 33 0.747043139 Controlled 0.95 14.94086277 14.19382 14.642046 0.448225883 9 $5,371 $11,983

NEICA0291026 GENERAL PRODUCTION SERVICE INC CONTROLLED 4 0.00480725 Controlled 0.95 0.096145 0.0913377 0.0942221 0.00288435 1 $597 $206,906

NEICA0291057 CHEVRON USA INC CONTROLLED 18 0.003501984 Controlled 0.95 0.07003968 0.0665377 0.0686389 0.00210119 5 $2,984 $1,420,121

NEICA0291061 BERRY PETROLEUM COMPANY CONTROLLED 17 0.000224334 Controlled 0.95 0.004486674 0.0042623 0.0043969 0.0001346 5 $2,984 $22,168,946

Attachment 6, page 1 4/17/2012
ATTACHMENT 6

Incremental Cost Effectiveness - Storage Vessels with the Potential for Flash Emissions

Values Existing Sources

NTI_SITE_ID FACILITY_NAME CONTROL_STATUS Count of Expr1 Sum of SumOfEMISSIONS_TPY Control Status Control Efficiency

Uncontrolled 

Emissions (tpy)

Emission 

Reduction 

at 95%

Emission 

Reduction 

at 98% Incremental ER

Number of 

Control 

Devices 

Required Incremental TAC Incremental CE

NEICA0291067 CHEVRON USA PRODUCTION COMPANY CONTROLLED 241 0.174658579 Controlled 0.95 3.49317159 3.318513 3.4233082 0.104795148 61 $36,404 $347,384

NEICA0291069 CHEVRON USA INC. CONTROLLED 1005 0.334083021 Controlled 0.95 6.681660425 6.3475774 6.5480272 0.200449813 252 $150,391 $750,267

NEICA0291080 TEJON PUMP STATION CONTROLLED 4 0.008282087 Controlled 0.95 0.165641744 0.1573597 0.1623289 0.004969252 1 $597 $120,096

NEICA0291091 CHEVRON PIPE LINE COMPANY CONTROLLED 8 0.047314887 Controlled 0.95 0.94629774 0.8989829 0.9273718 0.028388932 2 $1,194 $42,044

NEICA0291094 CHEVRON PIPE LINE COMPANY CONTROLLED 3 0.004130057 Controlled 0.95 0.082601139 0.0784711 0.0809491 0.002478034 1 $597 $240,832

NEICA0291096 CHEVRON PIPE LINE COMPANY CONTROLLED 3 0.076355419 Controlled 0.95 1.527108388 1.450753 1.4965662 0.045813252 1 $597 $13,027

NEICA0291098 CHEVRON PIPE LINE COMPANY CONTROLLED 4 0.00404186 Controlled 0.95 0.08083721 0.0767953 0.0792205 0.002425116 1 $597 $246,087

NEICA0291099 CHEVRON PIPE LINE COMPANY CONTROLLED 3 0.004870448 Controlled 0.95 0.097408954 0.0925385 0.0954608 0.002922269 1 $597 $204,221

NEICA0291105 DRILLING AND PROD, CENTRAL SRC CONTROLLED 14 0.014241923 Controlled 0.95 0.284838464 0.2705965 0.2791417 0.008545154 4 $2,387 $279,358

NEICA029976 STOCKDALE OIL & GAS CONTROLLED 39 0.01117655 Controlled 0.95 0.223531 0.2123545 0.2190604 0.00670593 10 $5,968 $889,942

NEICA029996 PETRO RESOURCES, INC CONTROLLED 32 0.047804259 Controlled 0.95 0.956085181 0.9082809 0.9369635 0.028682555 8 $4,774 $166,454

NEICA0371148 PETRO RESOURCES INC TRACK 6 8 CONTROLLED 9 0.006702387 Controlled 0.95 0.134047746 0.1273454 0.1313668 0.004021432 3 $1,790 $445,206

NEICA0371493 TIDELANDS OIL PRODUCTION CO CONTROLLED 1 0.001 Controlled 0.95 0.02 0.019 0.0196 0.0006 1 $597 $994,648

NEICA0531812 AERA ENERGY LLC CONTROLLED 1 0.0005 Controlled 0.95 0.01 0.0095 0.0098 0.0003 1 $597 $1,989,297

NEICA0592073 UNION OIL CO OF CALIFORNIA CONTROLLED 2 0.0000509 Controlled 0.95 0.001018 0.0009671 0.0009976 3.054E-05 1 $597 $19,541,225

NEICA0592079 UNION OIL CO OF CALIFORNIA (SI CONTROLLED 3 0.00022445 Controlled 0.95 0.004489 0.0042646 0.0043992 0.00013467 1 $597 $4,431,492

NEICA0592082 UNION OIL CO OF CALIFORNIA CONTROLLED 2 0.0001274 Controlled 0.95 0.002548 0.0024206 0.002497 7.644E-05 1 $597 $7,807,287

NEICA0592096 SHELL WESTERN E&P INC; (BREA F CONTROLLED 12 0.015099358 Controlled 0.95 0.301987162 0.2868878 0.2959474 0.009059615 3 $1,790 $197,621

NEICA0592133 GOLDEN WEST REF CO (EIS USE ON CONTROLLED 3 0.003666218 Controlled 0.95 0.073324361 0.0696581 0.0718579 0.002199731 1 $597 $271,301

NEICA0592136 UNION OIL CO OF CALIFORNIA CONTROLLED 2 0.000595617 Controlled 0.95 0.01191233 0.0113167 0.0116741 0.00035737 1 $597 $1,669,948

NEICA0834100 ORCUTT PUMP STATION CONTROLLED 1 0.02318 Controlled 0.95 0.4636 0.44042 0.454328 0.013908 1 $597 $42,910

NEICA0834310 VENOCO - CARPINTERIA CONTROLLED 1 0.00646 Controlled 0.95 0.1292 0.12274 0.126616 0.003876 1 $597 $153,970

NEICA10503 CHEVRON - COALINGA/KETTLEMAN CONTROLLED 169 0.000464394 Controlled 0.95 0.009287889 0.0088235 0.0091021 0.000278637 43 $25,662 $92,098,171

NEICA10557 MACPHERSON OIL COMPANY CONTROLLED 53 4.50102E-05 Controlled 0.95 0.000900204 0.0008552 0.0008822 2.70061E-05 14 $8,355 $309,376,022

NEICA10561 EXXON SAN JOAQUIN PRODUCTION CONTROLLED 8 0.00007852 Controlled 0.95 0.0015704 0.0014919 0.001539 0.000047112 2 $1,194 $25,334,904

NEICA10576 CHAPARRAL PETROLEUM INC.-WEST CONTROLLED 39 0.114401584 Controlled 0.95 2.288031671 2.1736301 2.242271 0.06864095 10 $5,968 $86,944

NEICA10601 PYRAMID OIL COMPANY CONTROLLED 67 0.08408289 Controlled 0.95 1.681657807 1.5975749 1.6480247 0.050449734 17 $10,145 $201,099

NEICA10604 KENNETH H HUNTER JR CONTROLLED 27 0.073667311 Controlled 0.95 1.473346225 1.3996789 1.4438793 0.044200387 7 $4,178 $94,513

NEICA10606 SAN JOAQUIN FACILITIES MNGMNT CONTROLLED 9 0.009958675 Controlled 0.95 0.199173498 0.1892148 0.19519 0.005975205 3 $1,790 $299,633

NEICA10718 MOBIL OIL CORP S TORRANCE UNIT CONTROLLED 2 0.00150075 Controlled 0.95 0.030015 0.0285143 0.0294147 0.00090045 1 $597 $662,768

NEICA1115534 VINTAGE PETROLEUM INC. CONTROLLED 18 0.000270585 Controlled 0.95 0.005411707 0.0051411 0.0053035 0.000162351 5 $2,984 $18,379,566

NEICA1115544 VINTAGE PETROLEUM CONTROLLED 38 0.000677612 Controlled 0.95 0.013552248 0.0128746 0.0132812 0.000406567 10 $5,968 $14,678,720

NEICA1115564 VINTAGE PETROLEUM INC. CONTROLLED 16 0.000085357 Controlled 0.95 0.00170714 0.0016218 0.001673 5.12142E-05 4 $2,387 $46,611,213

NEICA1115574 MOBIL EXPLORATION & PRODUCING CONTROLLED 8 0.0647101 Controlled 0.95 1.294202 1.2294919 1.268318 0.03882606 2 $1,194 $30,742

NEICA1115582 NUEVO ENERGY COMPANY CONTROLLED 9 0.002505832 Controlled 0.95 0.050116645 0.0476108 0.0491143 0.001503499 3 $1,790 $1,190,800

NEICA1115583 MIRADA PETROLEUM INC. CONTROLLED 7 0.00028671 Controlled 0.95 0.0057342 0.0054475 0.0056195 0.000172026 2 $1,194 $6,938,358

NEICA1115592 CONOCOPHILLIPS VENTURA STATION CONTROLLED 4 0.11946355 Controlled 0.95 2.389270992 2.2698074 2.3414856 0.07167813 1 $597 $8,326

NEICA1115601 TEXACO E&P INC - TEMESCAL FEE CONTROLLED 12 0.0105 Controlled 0.95 0.21 0.1995 0.2058 0.0063 3 $1,790 $284,185

NEICA1115645 EQUILON PIPELINE COMPANY LLC CONTROLLED 16 0.01344 Controlled 0.95 0.2688 0.25536 0.263424 0.008064 4 $2,387 $296,026

NEICA1115657 SENECA RESOURCES CORP. CONTROLLED 12 0.0016501 Controlled 0.95 0.033002 0.0313519 0.032342 0.00099006 3 $1,790 $1,808,342

NEICA1115659 SANTA FE ENERGY O P L P CONTROLLED 13 0.003423103 Controlled 0.95 0.06846205 0.0650389 0.0670928 0.002053861 4 $2,387 $1,162,277

NEICA1115662 AERA ENERGY LLC CONTROLLED 1 0.039534672 Controlled 0.95 0.79069344 0.7511588 0.7748796 0.023720803 1 $597 $25,159

NEICA1115664 SENECA RESOURCES CORP. CONTROLLED 5 0.00002394 Controlled 0.95 0.0004788 0.0004549 0.0004692 0.000014364 2 $1,194 $83,095,099

NEICA1115666 SHELL CALIFORNIA PIPELINE CONTROLLED 8 0.213700852 Controlled 0.95 4.274017036 4.0603162 4.1885367 0.128220511 2 $1,194 $9,309

NEICA1115668 SENECA RESOURCES CORP. CONTROLLED 8 0.001115151 Controlled 0.95 0.022303019 0.0211879 0.021857 0.000669091 2 $1,194 $1,783,881

NEICA1115673 MOBIL EXPLORATION & PRODUCING CONTROLLED 12 0.01178925 Controlled 0.95 0.235785 0.2239958 0.2310693 0.00707355 3 $1,790 $253,107

NEICA1115674 RINCON ISLAND LTD. PARTNERSHIP CONTROLLED 9 0.002648805 Controlled 0.95 0.052976108 0.0503273 0.0519166 0.001589283 3 $1,790 $1,126,525

NEICA1115676 SENECA RESOURCES CORPORATION CONTROLLED 4 0.00157795 Controlled 0.95 0.031559 0.0299811 0.0309278 0.00094677 1 $597 $630,342

NEICA1115683 I.T.G. ENERGY CORPORATION CONTROLLED 4 3.82077E-05 Controlled 0.95 0.000764153 0.0007259 0.0007489 2.29246E-05 1 $597 $26,032,691

NEICA1134322 VINTAGE PETROLEUM INC. CONTROLLED 30 0.007603007 Controlled 0.95 0.152060139 0.1444571 0.1490189 0.004561804 8 $4,774 $1,046,584

NEICA1134939 VINTAGE PETROLEUM CONTROLLED 2 0.001434781 Controlled 0.95 0.028695613 0.0272608 0.0281217 0.000860868 1 $597 $693,241

NEICA1514308 PHILLIPS PETROLEUM COMPANY CONTROLLED 4 0.011733547 Controlled 0.95 0.234670934 0.2229374 0.2299775 0.007040128 1 $597 $84,770

NEICA2683888 STOCKER RESOURCES INC CONTROLLED 1 0.00002 Controlled 0.95 0.0004 0.00038 0.000392 0.000012 1 $597 $49,732,416

NEICA5611344 VINTAGE PETROLEUM INC. CONTROLLED 6 0.000731107 Controlled 0.95 0.014622144 0.013891 0.0143297 0.000438664 2 $1,194 $2,720,937

NEICA5611345 VINTAGE PETROLEUM INC., S. MOUTAIN & W. MOUNTAIN CONTROLLED 10 0.060636 Controlled 0.95 1.21272 1.152084 1.1884656 0.0363816 3 $1,790 $49,211

NEICA6113454 VINTAGE PETROLEUM INC. CONTROLLED 17 0.02299775 Controlled 0.95 0.459955 0.4369573 0.4507559 0.01379865 5 $2,984 $216,249

NEICO1230048 KERR-MCGEE ROCKY MOUNTAIN CORP - HUDSON CONTROLLED 1 0.695118351 Controlled 0.95 13.90236702 13.207249 13.62432 0.417071011 1 $597 $1,431

NEICO1230184 KERR-MCGEE FREDERICK CS CONTROLLED 1 0.125453 Controlled 0.95 2.50906 2.383607 2.4588788 0.0752718 1 $597 $7,928

NEICO1230185 KERR-MCGEE ROCKY MOUNTAIN CORP - DOUGAN CONTROLLED 1 0.1322256 Controlled 0.95 2.644512 2.5122864 2.5916218 0.07933536 1 $597 $7,522

NEILA0048 DYNEGY MIDSTREAM SVCS LP/DELTA GATHERING CONTROLLED 3 1.25184 Controlled 0.95 25.0368 23.78496 24.536064 0.751104 1 $597 $795

NEILA0050018 ENTERPRISE GAS PROC LLC/TEBONE FRAC PLANT CONTROLLED 1 0.46 Controlled 0.95 9.2 8.74 9.016 0.276 1 $597 $2,162

NEILA0098 LA LAND & EXPLOR - E LAKE SAND CONTROLLED 2 0.0135 Controlled 0.95 0.27 0.2565 0.2646 0.0081 1 $597 $73,678

NEILA0123 GULFPORT ENERGY CORP/W COTE BLANCHE BAY DEHY CONTROLLED 1 0.23472 Controlled 0.95 4.6944 4.45968 4.600512 0.140832 1 $597 $4,238

NEILA0510033 EXXONMOBIL PROD CO/GRAND ISLE GAS PLANT AND BASE CONTROLLED 1 0.1695 Controlled 0.95 3.39 3.2205 3.3222 0.1017 1 $597 $5,868

NEILA0510142 BP AMERICA PROD CO/GRAND ISLE TB CONTROLLED 1 0.013 Controlled 0.95 0.26 0.247 0.2548 0.0078 1 $597 $76,511

NEILA0570008 TEXAS PETROLEUM INVESTMENT CO/DELTA FARMS PRODUCTION FACILITY CONTROLLED 12 0.408 Controlled 0.95 8.16 7.752 7.9968 0.2448 3 $1,790 $7,314

NEILA0750205 BP AMERICA PROD CO/GRAND BAY RECEIVING STN CONTROLLED 3 0.1795 Controlled 0.95 3.59 3.4105 3.5182 0.1077 1 $597 $5,541

NEILA0870011 DYNEGY MIDSTREAM SVCS LP/YSCLOSKEY CONTROLLED 1 0.1025 Controlled 0.95 2.05 1.9475 2.009 0.0615 1 $597 $9,704

NEILA13525 TEXAS PETROLEUM INVESTMENT CO/AVERY ISLND PETIT ANSE BATTERY CONTROLLED 2 0.156479999 Controlled 0.95 3.129599972 2.97312 3.067008 0.093887999 1 $597 $6,356

NEILA13682 DYNEGY MIDSTREAM SVCS LP/VENICE GAS PROC CONTROLLED 2 0.243 Controlled 0.95 4.86 4.617 4.7628 0.1458 1 $597 $4,093

NEIMI055B915 MERIT ENERGY CO. - GRANT 29 CONTROLLED 2 0.0257 Controlled 0.95 0.514 0.4883 0.50372 0.01542 1 $597 $38,702

NEIMI14248 MERIT ENERGY CO. - FREDERIC 20 CONTROLLED 2 0.00847 Controlled 0.95 0.1694 0.16093 0.166012 0.005082 1 $597 $117,432

NEIMI14392 MERIT ENERGY CO. - OTSEGO LAKE 34 CONTROLLED 2 0.00828 Controlled 0.95 0.1656 0.15732 0.162288 0.004968 1 $597 $120,127

NEIMIB5584 MERIT ENERGY CO. - BLUE LAKE 27 CONTROLLED 1 0.00194 Controlled 0.95 0.0388 0.03686 0.038024 0.001164 1 $597 $512,705

NEIMIB9135 MERIT ENERGY CO. - BEAR LAKE 13 CONTROLLED 2 0.04041 Controlled 0.95 0.8082 0.76779 0.792036 0.024246 1 $597 $24,614

NEIMIB9136 MERIT ENERGY CO. - BEAR LAKE 22 CONTROLLED 2 0.04249 Controlled 0.95 0.8498 0.80731 0.832804 0.025494 1 $597 $23,409

NEIMIB9142 MERIT ENERGY COMPANY - CHARLTON 12 CONTROLLED 2 0.01673 Controlled 0.95 0.3346 0.31787 0.327908 0.010038 1 $597 $59,453

NEIMIB9160 MERIT ENERGY COMPANY - MAPLE GROVE 16 CONTROLLED 2 0.02371 Controlled 0.95 0.4742 0.45049 0.464716 0.014226 1 $597 $41,951

NEIMIN6466 QUICKSILVER RESOURCES INC. - ST. KALKASKA 1-10 CONTROLLED 2 0.16737 Controlled 0.95 3.3474 3.18003 3.280452 0.100422 1 $597 $5,943

NEIMIN6468 QUICKSILVER RESOURCES INC - USA KALKASKA 3-20 CONTROLLED 2 0.16443 Controlled 0.95 3.2886 3.12417 3.222828 0.098658 1 $597 $6,049

NEIMIN6470 QUICKSILVER RESOURCES INC - USA KALKASKA 1-30 CONTROLLED 2 0.05398 Controlled 0.95 1.0796 1.02562 1.058008 0.032388 1 $597 $18,426

NEIMIN6473 MERIT ENERGY COMPANY - ALBERT 25 CPF CONTROLLED 1 0.0785 Controlled 0.95 1.57 1.4915 1.5386 0.0471 1 $597 $12,671

Attachment 6, page 2 4/17/2012
ATTACHMENT 6

Incremental Cost Effectiveness - Storage Vessels with the Potential for Flash Emissions

Values Existing Sources

NTI_SITE_ID FACILITY_NAME CONTROL_STATUS Count of Expr1 Sum of SumOfEMISSIONS_TPY Control Status Control Efficiency

Uncontrolled 

Emissions (tpy)

Emission 

Reduction 

at 95%

Emission 

Reduction 

at 98% Incremental ER

Number of 

Control 

Devices 

Required Incremental TAC Incremental CE

NEIOK1532533 ONEOK FIELD SVC CONTROLLED 12 9.4668272 Controlled 0.95 189.336544 179.86972 185.54981 5.68009632 3 $1,790 $315

NEIOK1954 SUNOCO PIPELINE LP CONTROLLED 2 4.44 Controlled 0.95 88.8 84.36 87.024 2.664 1 $597 $224

NEIOK1955 SUNOCO PIPELINE LP CONTROLLED 3 0.445 Controlled 0.95 8.9 8.455 8.722 0.267 1 $597 $2,235

NEIOK1957 SUNOCO PIPELINE LP CONTROLLED 2 3.16 Controlled 0.95 63.2 60.04 61.936 1.896 1 $597 $315

NEIOK1960 SUNOCO PIPELINE LP CONTROLLED 2 7.7 Controlled 0.95 154 146.3 150.92 4.62 1 $597 $129

NEIOK1965 SUNOCO PIPELINE LP CONTROLLED 8 30.17728704 Controlled 0.95 603.5457408 573.36845 591.47483 18.10637222 2 $1,194 $66

NEIOK1972 SUNOCO PIPELINE LP CONTROLLED 2 0.98 Controlled 0.95 19.6 18.62 19.208 0.588 1 $597 $1,015

NEIOK1979 SUNOCO PIPELINE LP CONTROLLED 2 6.03 Controlled 0.95 120.6 114.57 118.188 3.618 1 $597 $165

NEIOK1984 SUNOCO PIPELINE LP CONTROLLED 2 11.97 Controlled 0.95 239.4 227.43 234.612 7.182 1 $597 $83

NEIOK1986 SUNOCO PIPELINE LP CONTROLLED 1 0.045 Controlled 0.95 0.9 0.855 0.882 0.027 1 $597 $22,103

NEIOK1988 SUNOCO PIPELINE LP CONTROLLED 4 2.54 Controlled 0.95 50.8 48.26 49.784 1.524 1 $597 $392

NEIOK1990 SUNOCO PIPELINE LP CONTROLLED 6 10.86 Controlled 0.95 217.2 206.34 212.856 6.516 2 $1,194 $183

NEIOK2002 ONEOK FIELD SVC CONTROLLED 9 11.5031896 Controlled 0.95 230.063792 218.5606 225.46252 6.90191376 3 $1,790 $259

NEIOK2506 ONEOK FIELD SVC CONTROLLED 12 11.17577728 Controlled 0.95 223.5155456 212.33977 219.04523 6.705466368 3 $1,790 $267

NEIOK2523 ONEOK FIELD SVC CONTROLLED 6 5.3094304 Controlled 0.95 106.188608 100.87918 104.06484 3.18565824 2 $1,194 $375

NEIOK2527 ONEOK FIELD SVC CONTROLLED 12 12.99809984 Controlled 0.95 259.9619968 246.9639 254.76276 7.798859904 3 $1,790 $230

NEIOK2529 ONEOK FIELD SVC CONTROLLED 12 16.2473184 Controlled 0.95 324.946368 308.69905 318.44744 9.74839104 3 $1,790 $184

NEIOK401394889 DCP MIDSTREAM LP CONTROLLED 1 12.75311989 Controlled 0.95 255.0623978 242.30928 249.96115 7.651871933 1 $597 $78

NEITX157312F THOMPSON COMPRESSOR STATION 3 CONTROLLED 3 1.319212464 Controlled 0.95 26.38424928 25.065037 25.856564 0.791527478 1 $597 $754

NEITX167130 ALTA LOMA COMPRESSOR STATION CONTROLLED 14 0.054212496 Controlled 0.95 1.08424991 1.0300374 1.0625649 0.032527497 4 $2,387 $73,389

NEITX339063W CONROE CENTRAL TREATING STATION CONTROLLED 2 0.789957984 Controlled 0.95 15.79915968 15.009202 15.483176 0.47397479 1 $597 $1,259

NEITX365069E CARTHAGE COMPRESSOR STATION NO 1 CONTROLLED 4 1.114684261 Controlled 0.95 22.29368521 21.179001 21.847812 0.668810556 1 $597 $892

NEITXRAA0045 MOSBACHER ENERGY CO. CONTROLLED 2 0.10507632 Controlled 0.95 2.1015264 1.9964501 2.0594959 0.063045792 1 $597 $9,466

NEITXRCB0053 GAS PROCESSING FACILITIES CONTROLLED 10 0.019 Controlled 0.95 0.379999997 0.361 0.3724 0.0114 3 $1,790 $157,050

NEITXRUA0156 INDIAN ROCK GAS PLANT CONTROLLED 1 0.019771248 Controlled 0.95 0.39542496 0.3756537 0.3875165 0.011862749 1 $597 $50,308

Attachment 6, page 3 4/17/2012
Attachment 7

Cost Effectiveness on Component Basis

Processing Plant Cost Effectiveness Summary

Valves

LDAR Program 

Total Capital 

Investment

Annual LDAR 

Cost ($/yr)

Recovery 

Credits ($/yr)1

Annual LDAR 

Cost w/o 

Recovery 

Credits ($/yr)

Total CH4 

Emission 

Reductions

CH4 Cost 

Effectiveness 

($/Ton)

Total VOC 

Emission 

Reductions

VOC Cost 

Effectiveness 

($/Ton)

Total HAP 

Emission 

Reductions

HAP Cost 

Effectiveness 

($/Ton)

Subpart VVa $1,577 $1,839 $1,839 6.6 $281 1.82 $1,010 0.069 $26,789

100 ppm $5,507 $2,220 $2,220 3.3 $680 0.91 $2,447 0.034 $64,912

LDAR Program 

Total Capital 

Investment

Annual LDAR 

Cost ($/yr)

Recovery 

Credits ($/yr)1

Annual LDAR 

Cost w/ 

Recovery 

Credits ($/yr)

Total CH4 

Emission 

Reductions

CH4 Cost 

Effectiveness 

($/Ton)

Total VOC 

Emission 

Reductions

VOC Cost 

Effectiveness 

($/Ton)

Total HAP 

Emission 

Reductions

HAP Cost 

Effectiveness 

($/Ton)

Subpart VVa $1,577 $1,839 $1,519 $321 6.6 $49 1.82 $176 0.069 $4,671

100 ppm $5,507 $2,220 $757 $1,464 3.3 $449 0.91 $1,613 0.034 $42,794

380 Natural gas Mscf/yr

189 Natural gas Mscf/yr

Processing Plant Cost Effectiveness Summary

Connectors

LDAR Program 

Total Capital 

Investment

Annual LDAR 

Cost ($/yr)

Recovery 

Credits ($/yr)1

Annual LDAR 

Cost w/ 

Recovery 

Credits ($/yr)

Total CH4 

Emission 

Reductions

CH4 Cost 

Effectiveness 

($/Ton)

Total VOC 

Emission 

Reductions

VOC Cost 

Effectiveness 

($/Ton)

Total HAP 

Emission 

Reductions

HAP Cost 

Effectiveness 

($/Ton)

Subpart VVa $7,924 $4,167 $0 $4,167 9.8 $424 2.74 $1,523 0.103 $40,411

LDAR Program 

Total Capital 

Investment

Annual LDAR 

Cost ($/yr)

Recovery 

Credits ($/yr)1

Annual LDAR 

Cost w/ 

Recovery 

Credits ($/yr)

Total CH4 

Emission 

Reductions

CH4 Cost 

Effectiveness 

($/Ton)

Total VOC 

Emission 

Reductions

VOC Cost 

Effectiveness 

($/Ton)

Total HAP 

Emission 

Reductions

HAP Cost 

Effectiveness 

($/Ton)

Subpart VVa $7,924 $4,167 $2,281 $1,887 9.8 $192 2.74 $690 0.103 $18,293

570 Natural gas Mscf/yr

Cost Effectiveness w/ Recovery Credits

Cost Effectiveness w/o Recovery Credits

Cost Effectiveness w/ Recovery Credits

Cost Effectiveness w/o Recovery Credits

Attachment 7, page 1 4/17/2012
Attachment 7

Type of Component Number of 

Components

Initial 

Monitoring 

Fee or Unit 

Cost ($/comp)

Initial 

Monitoring 

Costs ($/yr) 

(Capital)

Initial LDAR 

Admin. Costs

Frequency of 

Monitoring 

(times/yr)

Subsequent 

Monitoring 

Fee ($/comp) 

or Charge (%)

Annual 

Monitoring 

Costs ($/yr)

Annual 

Maintenance 

Costs ($/yr)

Initial Leak 

Fraction

Initial Number 

of Leaks

Subsequent 

Leak 

Frequency (%)

Annual 

Number of 

Leaks

Percent 

Repaired 

OnLine

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual OnLine 

Leak Repair 

Cost ($/yr)

Percent 

Requiring 

Further Repair

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual Offline 

Leak Repair 

Cost ($/yr)

Monitoring to 

Verify Repair 

($)

Annual Admin. 

Cost ($/yr)

Annual Misc. 

Charges ($/yr)

Valves (UU)

 * Gas/vapor service 1,392 23.80 33519.82 12 1.50 25056.00 0.0118 16.43 1.18 197.11 95 0.17 66.24 132.74 5 4.00 66.24 2611.28

Connectors

 * Flanges - gas/vapor 1.10 0.00

Pressure Relief Devices

 * Disks 122.11 0.00

 * Disk holders, valves,etc. 6374.29 0.00

Open-Ended Lines 140.92 0.00

Monitoring Device 1 $10,800 $10,800

Monitoring Device - Rent 0

Data Collection System 1 $14,500 $14,500

Sum of components: 1392

Annual Adminstrative and Reports 250 92.72 $23,180

 - Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670

 - Assume 340 hr per fac

TOTALS $58,820 $29,670 $25,056 $0 $132.74 $2,611.28 $23,180 $0.00

Capital Costs $58,820

Annualized Capital Costs $13,300

Annual Expenses $50,980

Annual Fixed Costs ($/yr) $36,480

Annual Variable Costs ($/yr) $27,800

Total Annual Costs ($/yr) $64,280

Technology Review Average Processing Plant Costs_041712.xlsx

Valves - VV Attachment 7, page 2 4/17/2012
Attachment 7

Type of Component Number of 

Components

Initial 

Monitoring 

Fee or Unit 

Cost ($/comp)

Initial 

Monitoring 

Costs ($/yr) 

(Capital)

Initial LDAR 

Admin. Costs

Frequency of 

Monitoring 

(times/yr)

Subsequent 

Monitoring 

Fee ($/comp) 

or Charge (%)

Annual 

Monitoring 

Costs ($/yr)

Annual 

Maintenance 

Costs ($/yr)

Initial Leak 

Fraction

Initial Number 

of Leaks

Subsequent 

Leak 

Frequency (%)

Annual 

Number of 

Leaks

Percent 

Repaired 

OnLine

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual OnLine 

Leak Repair 

Cost ($/yr)

Percent 

Requiring 

Further Repair

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual Offline 

Leak Repair 

Cost ($/yr)

Monitoring to 

Verify Repair 

($)

Annual Admin. 

Cost ($/yr)

Annual Misc. 

Charges ($/yr)

Valves (UU)

 * Gas/vapor service 1,392 23.80 35097.25 12 1.50 25056.00 0.0595 82.82 1.91 319.05 95 0.17 66.24 132.74 5 4.00 66.24 4226.73

Connectors

 * Flanges - gas/vapor 1.10 0.00

Pressure Relief Devices

 * Disks 122.11 0.00

 * Disk holders, valves,etc. 6374.29 0.00

Open-Ended Lines 140.92 0.00

Monitoring Device 1 $10,800 $10,800

Monitoring Device - Rent 0

Data Collection System 1 $14,500 $14,500

Sum of components: 1392

Annual Adminstrative and Reports 250 92.72 $23,180

 - Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670

 - Assume 340 hr per fac

TOTALS $60,397 $29,670 $25,056 $0 $132.74 $4,226.73 $23,180 $0.00

Capital Costs $60,397

Annualized Capital Costs $13,524

Annual Expenses $52,595

Annual Fixed Costs ($/yr) $36,704

Annual Variable Costs ($/yr) $29,415

Total Annual Costs ($/yr) $66,119

Technology Review Average Processing Plant Costs_041712.xlsx

Valves - VVa Attachment 7, page 3 4/17/2012
Attachment 7

Type of Component Number of 

Components

Initial 

Monitoring 

Fee or Unit 

Cost ($/comp)

Initial 

Monitoring 

Costs ($/yr) 

(Capital)

Initial LDAR 

Admin. Costs

Frequency of 

Monitoring 

(times/yr)

Subsequent 

Monitoring 

Fee ($/comp) 

or Charge (%)

Annual 

Monitoring 

Costs ($/yr)

Annual 

Maintenance 

Costs ($/yr)

Initial Leak 

Fraction

Initial Number 

of Leaks

Subsequent 

Leak 

Frequency (%)

Annual 

Number of 

Leaks

Percent 

Repaired 

OnLine

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual OnLine 

Leak Repair 

Cost ($/yr)

Percent 

Requiring 

Further Repair

Repair Time 

(hours)

Labor Charge 

($/hr)

Annual Offline 

Leak Repair 

Cost ($/yr)

Monitoring to 

Verify Repair 

($)

Annual Admin. 

Cost ($/yr)

Annual Misc. 

Charges ($/yr)

Valves (UU)

 * Gas/vapor service 1,392 23.80 40603.75 12 1.50 25056.00 0.1473 205.04 1.28 213.81 90 0.17 66.24 132.74 10 4.00 66.24 5665.14

Connectors

 * Flanges - gas/vapor 1.10 0.00

Pressure Relief Devices

 * Disks 122.11 0.00

 * Disk holders, valves,etc. 6374.29 0.00

Open-Ended Lines 140.92 0.00

Monitoring Device 1 $10,800 $10,800

Monitoring Device - Rent 0

Data Collection System 1 $14,500 $14,500

Sum of components: 1392

Annual Adminstrative and Reports 250 92.72 $23,180

 - Assume 300 hr per fac

Initial Planning and Training 320 92.72 $29,670

 - Assume 340 hr per fac

TOTALS $65,904 $29,670 $25,056 $0 $132.74 $5,665.14 $23,180 $0.00

Capital Costs $65,904

Annualized Capital Costs $14,306

Annual Expenses $54,034

Annual Fixed Costs ($/yr) $37,486

Annual Variable Costs ($/yr) $30,854

Total Annual Costs ($/yr) $68,340

Technology Review Average Processing Plant Costs_041712.xlsx

Valves - 100 ppm Attachment 7, page 4 4/17/2012