# E C 

# / R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North C arolina 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 Stor age 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 describe d 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 (a rea 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 pr actices, 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 in cluded 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 pr esents 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 consulte d 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 U niform S tandards.

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 incre ase 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 pol lution 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 a mbient 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 ai r 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 pollut ion 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 statio nary 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 loca te applicable control technologies. On April 3, 2012, w e 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 486210 2 

### 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 n ame and process notes;

 Throughput;

 Pollutant;

 Control t echnology and e mission l imit ; and

 Percent e fficiency of c ontrol

. The results of the searc h 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, process es, 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
o perational 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/wel come_eg.html

. 2 2 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 ga s 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 regulatio ns suggested by the commenters 3 

### as 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 subpar t 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 H H 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 produ cts 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 prio r 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 ca tegory 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 equipment 4 

### and compressors (i.e., equipment leaks ) at natural gas processing plants (NGPP)

.
T he 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 G LYCOL DEHYDRATION UNITS
Glycol d ehydration 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 cond ensate 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 a ccount 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 accoun ting for the remaining portion.
This section presents the technology review conducted for glycol dehy dration 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 pre sents 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. F or the 1999 glycol dehydrator MACT standard s 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 rat e 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 combinatio n 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 

### A t 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

- GLYCalc TM 

### (Version 3.0) that 95 percent reduction w as appropriate as MAC T . 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
an d 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 estimat e 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 fo r 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. Recommenda tion 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

- 0 6

.

### 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 con trols (condensers; combustion devices, including catalytic incinerators and thermal incinerators; and carbon bed adsorbers) and pollution prevention. For e ach 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. 7 

### In addition, glycol dehydration unit process vents 8 

### that are connected to a process natural gas line are considered to be in compliance with the MACT standards. Table 1 p resents 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 per cent 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 po tential 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 pr eviously 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 I

n j ection
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 tech nology 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 Dat abase

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/d ay Therm al Oxidizer. Designed For 1400 o F and 0.5 Second Residence. 98

MI

- 0325 Michigan

Consolidated Gas (Belle River Mills) MI Glycol Dehydrator 986 MMscf/d ay Enclosed Flare Control o f Still Off Gas. 99

MI

- 0325 Michigan

Consolidated Gas (Belle River Mills) MI Glycol Dehydrator 986 MMscf/d ay Enclosed Flare Control o f Still O ff

- Gas 99

OK

- 0026 Swift Energy OK Dehydration Unit 20 MMscf/d ay Flare 99
NOTE: Only entries with emission reductions equal to or greater than 95 percent are presented.

### Table 2. Natural Gas STAR Program Glycol Dehydratio n 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 re

routed skimmer gas Process modification 790 (for 20

MMscf/day unit) No informa tion 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 Un its 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 emissi ons 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 pres sure 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 em issions. Equipment includes flash tanks, electric pumps, and electric control valves. Collect all condensable components from the still column vapor and use the remaining non

condensable still vapor as fuel for the glycol reboiler. Requires electric utilit ies 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. Natur al 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 Dehy drators By optimizing the glycol circulation rate,

th e 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 over

circulated and no flash tank exists Process Modification Range from

370 to 37,000 No information was

provided on th e 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 g lycol 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.

Ele ctricity 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 Gl ycol 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 great er than 5 million cubic feet per day (5 MMscfd). Usually used by partners when the volume to be drie d is 5 MMscf/day or less and when wellhead gas temperature is low (< 70 o F) 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. Equi pment 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. 16 E PA (2006). Lessons Learned: Replacing Glycol Dehydrators with Desiccant Dehydrators. Natural Gas STAR.

### 10

Table 3. State Regulations for Glycol Dehydrators

- Greater Than 95 Perce nt 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 resul t, 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 dehydrator s 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 s heet (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 feas ible.
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 Engineering 21 

### cost index for equipment cost s. To develop the TCI for the zero emissions dehydrator, the cost information in the PRO Fact Sheet No. 206 22 

### was used. It was reported in the PRO Fact Sheet No. 206 that the cost data repre sented equipment sized for a 28 MMscf/day glycol dehydrator. The s e estimates were based
on 2011 cost data. Therefore, the cost data were revised to reflect 2008 dollars using the Chemical Engineering 23 

### 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 equi pment 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 eq uipment 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 differen ce between the sunk cost of the condenser plus flash tank and the zero emis sions dehydrator. 20 See Reference 7

. 21 Chemical Engineering. http://www.che.com. August 2004. Economic Indicators. 22 See Reference 13

. It wa s 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 Prot ection 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 esti mating 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 als o 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 tra nsmission 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 acc ordingly. 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 c ondenser 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 pres ented 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, a ssuming 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 p ercent 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 dehydratio n 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

Cost a 

### Condenser Condenser,

piping to control device All 28 $6,800 b 

### $9,92 1

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 invest ment 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. b Direct and indirect costs are included in the condenser cost.

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

. d Total 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 Cost a ,b Condenser c Condenser (assum e

includes piping to control device ) 28 MM scf/d $14,000

-

$25,000 $11,821 $11,451

Electric Pump c 28 MMscf/d $1,400

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

Flash tank c 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 costs d 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

a Costs scaled fro m 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. b Costs scaled to system sized for an average throughput of 17 MMscf/day in the MACT dataset ( see Attachment 2).

c Capital 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.

e Tota l 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 Operati ng labor 130 hours/yr x $technical labor rate b $3,960 $3,960 Supervising labor 0.15 x Operating labor x management labor rate c 937 937 Operating materials None required 0 0 Maintenance Labor 130 hours/yr x $technical labor rate b 3,960 3, 960 Material 0.50 x Maintenance labor c 1,980 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 TCIE d 397 1,162 Property tax 0.01 x TCIE d 199 581 Insurance 0.01 x TCIE d 199 581 Capital recovery e 0.1 098 x TCIE d 2,181 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 ). b Technical Labor Rate = $30.4 6/hr (Reference 36 )

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

. d TCIE from Table 4 for c ondenser and Table 5 for zero emissions dehydrator.

e Capital 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

Cost a 

### Condenser Condenser,

piping to control device All 38 

### $6,8 00 b 

### $9,92 1

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

Enhance d 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. b Direct and indirect costs are included in the condenser cost.

c Procedures followed from OAQPS Control Cost Manual for calculating P EC and TCI (Reference 42 )

. d Total 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 Fa ctor Oct 2011 Cost 2008 Cost a,b Condenser c Condenser (assum e

includes piping to control device ) 28 MMscf/d $14,000

-

$25,000 $74,453 $72,121

Electric Pump c 28 MMscf/d $1,400

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

Flash tank c 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 costs d Founda tion 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 Cos ts (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 Indi rect Costs (IC) $56,675 Total capital investment for an existing unit (TCIE) e 1.15(PEC + DC + IC ) $318,113

a Costs scaled from October 2011 dollars to 2008 dollars using the ratio of Chemical Engineering cost indices (Reference 43 ). October 2011 Cost In dex = 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 )

. c Capital Cost provided by Natural Gas STAR PRO FS 206 (Reference 44 ) Capital cost assumed to be PEC. Assum ed that the mid point of the range represents the 28 MMscf/day dehydration unit

. d Site prep and building n ot included in this assessment, assumed that site prep was already performed and building already exist s.
e Total capital investment for an existing uni t accounts for a retrofit factor of 1.15.

43 See Ref

erence 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 rate b $3,960 $3,960 Supervising labor 0.15 x Operating labor x management labor rate c 937 937 Operating materials None required 0 0 Maintenance Labor 130 hours/yr x $technical labor rate b 3,960 3,960 Material 0.50 x Maintenance labor c 1,980 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

Indi rect Annual Costs (IAC) a Overhead 0.60 x Total labor plus Maintenance materials $5,314 $5,314 Administrative 0.02 x TCIE d 397 7,317 Property tax 0.01 x TCIE d 199 3,658 Insurance 0.01 x TCIE d 199 3,658 Capital recovery e 0.1098 x TCIE d 2,181 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 ). b Technical Labor Rate = $30.46/hr (Reference 46 )

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

. d TCIE from Table 6 7 for Condenser and Table 7 8 for zero emissions dehydrator.

e Capital 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 units a ,b 

### 92 15

Wit hout 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 tha n 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 exp ected 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 HAP 48 

### 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 metha ne content of 79 percent for production 49 

### 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 foll ows:

 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 transmi ssion 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 i n 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 de hydrator 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 un certainties, 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

. 50 Need a cost reference for gas prices.

### 21

Desiccant Dehydrators

Under certain operating conditions , d esiccant 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 70 o 

### F) 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 absorb s moisture from the gas, the operators periodically need to refill the desiccant. Refil ling 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 d ump 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 dri ed is 5 MM s cf / d ay 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, coolin g 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 d ata, have inlet gas temperatures greater than 70 o 

### F 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 natur al 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 t hese 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 separato r 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 improv ement 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 instal lation 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 reduct ions 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 

### T he 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 combus tor. 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 operat ing 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 annua l 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 assume d that all controlled large glycol dehydration units were subject to and controlled under subpart s HH and HHH . Using this assumption, uncontrolled emissions were calculated using a 95 percent control efficiency, prior to use of the combustor. The incremen tal 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 de hydration 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/t on, 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 En vironment 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 reductio ns 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. 59 Memorandum 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 Item a 

### Capital Costs ($) Non

Recurring, One

- ti me 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 System d 

### $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 dat a 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 c osts.

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 i s 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 us ing the CE Indices for 2007 (525.4) and 2008 (575.4) ( Reference 61

.

60 Initial Economic Impact Analysis for Proposed State

- Only Revis ions 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 Nat ural Gas

Transmission and Storage Number of large dehydration units a 

### 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 prod uction 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 an d 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 perce nt, 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 o f 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 fi eld. 62 

### Based on this analysis, we conclude that 98 and 99 percent control are neither technologically n or economically feasible at this time

. 4.2.3 Work Practices and Procedures Not Identified and Considered During MACT Development
Table 2 presents sever al 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 pro cess 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 mean s 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 de vice s . Further, the documents presented by the Natural Gas STAR program do not provide emission reduction estimates by which a cost ef fectiveness evaluation could be conducted

.
4.2.4 Process Changes or Pollution Prevention Alternatives That Could Be Broad ly 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 i dentified 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 (ft 3 

### /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

- 20 10

- 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 typical ly 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 sourc e 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 wheth er 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 (subp art 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 captu red 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 s torage 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 flo ating 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 t o 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 sea rch 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 achie ve 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 consider ed potential development s in practices, process es , and control technologies for the subpar t 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 emissio n 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 pressurize d 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 pl ants 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 co nsidered 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 opera ted 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, t he 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 P otential 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 capt ure 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 percen t 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 co ntrol 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 pressuri zed 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; consoli date 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 Nat ural 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 ft 3 

### /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 captu re 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 techn ology 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 th e 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 tha t 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 da ta 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 com bustors, 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% Contr ol)

State Source Applicability Standard Compliance Options WY New and Existing Sources; ≥0

- 20 tpy VOC (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 Item a 

### Capital

Costs ($) Non

Recurring, One

- time Costs ($) Tot al

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) Subtota l 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 Ass ume 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 cos ts, 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 1 6 . Summary of Incremental Cost Effectiveness (ICE) Associated with Raising the Emission Reduction to 98 Pe rcent

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 consider ed 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 r emotely 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 Dev elopment
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, flang es, 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 cons tituents 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 MAC T 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 technologi es 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 serv ice, 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 piece s 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 conta ins 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 6 1, 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 relie ve 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 o f the 1999 MACT standard, the control opt i on s 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 A ncillary 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 equipme nt 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, t he Uniform S tandards, 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 complian ce, using a model plant approach. 77 

### I nformation summarized in the US memorandum was relevant and therefore was used in the technology review for equipment leak standards under subpart HH.

N o entirely new developments in methods for controlling equipment le ak emissions were found

. 78 

### Since the 1999 MACT, t he 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 pla ce 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 memorand um 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 Leak s. 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 off

er 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 6 3

. 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 6 3

. 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 intend s 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, p acking combinations for valves and gaskets for fla nges 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 te chnology 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

S ome local regulati ons 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 D istri ct (SCAQMD) requires continuous monitoring of a percentage of atmospheric PRDs at refineries by installing a mo nitoring device capable of recording the duration of each rel ease and quantifying emissions. Wireless technology allows continuous monitorin g 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 , i t 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 b e associated with additional monitoring and repair. Likewise, i t 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, a dditional 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 1 8 limit s the number of components awa iting 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 provid e s incremental costs associated with their amendment that lower s 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 th e 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 emissio n 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 t his 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, t he EPA issued 40 CFR part 60, subpart VVa, which : lowered the leak definition fo r valves to 500 ppm; and requires monitoring for connectors with a new leak definition of 500 ppm. In addition, the BAAQMD equipment leak standards 85 

### establish a leak definit ion 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

– E quipment 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 t he US memorandum , model plants were developed to represent equipment counts found at different types of chemical and refi ning 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 effectivene ss of different compliance options, w e 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 se rvice, 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 connec tors 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 es timates, 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 Docum ent. 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 contro l 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 N ew 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 O ptions 89

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 annua l instrument monitoring to demonstrate that the OEL operates with an instrument reading of 500 ppm a Pressure Relief Devices Operate with no

detectable emissions (500 ppm) or install rupture disk or rout e to air pollution control device. PRD Wireless moni toring of PRDs b

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 additi onal 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 (Incre mental 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 Cost c $64,280 $ 66 ,119 $68,340 Incremental Annual Cost d -- $32 1/yr e $1,464

Cost Effectiveness f

-- $4,671/ton $42,794/ton Connectors Emissions 0.166 tpy 0.063 tpy Emission Reduction

-- 0.103 tpy Total Annual Cost c

-- g $1,887 Incremental Annual Cost d $1,887 e

Cost Effectiveness f

-- $ 18,293 /ton Minor d iscrepancies are due to rounding.

a Option 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 a re 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:

g No 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 TECHNOLOGY 0 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, 2012ATTACHMENT 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 CATALYSTMIRATECHSP-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 CATALYSTMIRATECH 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 CATALYSTMIRATECH SP-RESIGA90S3624X61-42-H4 0.12 G/HP-H 60 N

Attachment 1, page 2 April 3, 2012ATTACHMENT 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 CATALYSTMIRATECH 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 CATALYSTMIRATECH 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 WEEKLY MONITORING 1.5 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 VENTILATION 2 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/H EQUIP: 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 RECOVERY PROJECT, FUEL_TYPE: , SCHEDULE: CONTINUOUS, H/D: 24, D/W: 7, W/Y: 365, NOTES: PART OF THE DIATOMITE PROJECT WHICH HAS TWO 62.50 MMBTU/HR STEAM GENERATORS BOTH WITH SIMILAR CONTROL REQUIREMENTS (SEE BACT DETERMINATION FOR ATC 12084). SOURCE TEST RESULTS: ALL PPMVD READINGS AT 3% OXYGEN THREE TEST LOADS RUN WITH FGR NORMAL FGR OPERATION: NOX 8.3 PPMVD CO 0.0 PPMVD ROC 0.0 PPMVD MINIMUM FGR: NOX 8.9 PPMVD CO 0.0 PPMVD ROC 0.0 PPMVD MAXIMUM FGR: NOX 7.2 PPMVD CO 0.0 PPMVD ROC 0.0 PPMVD TESTED ON FEBRUARY 23, 2007. ST PROJECT NUMBER 228-5232 BY AEROS ENVIRONMENTAL ROC Volatile 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/H EQUIP: 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 RECOVERY PROJECT, FUEL_TYPE: , SCHEDULE: CONTINUOUS, H/D: 24, D/W: 7, W/Y: 365, NOTES: GENERATOR DESIGN: 1160 PSIG @ 564F. BURNER IS NORTH AMERICAN MFG MODEL 4211-24G-LE ULTRA LOW NOX DESIGN WITH A ROSEMOUNT WORLD CLASS 3000 EXCESS O2 TRIM CONTROL AND FLUE GAS RECIRCULATION (FGR). WELL STEAMING WILL CONSIST OF INJECTING STEAM INTO SEVERAL WELLS IN EACH POD FOR THREE TO FIVE DAYS. THE STEAM WILL THEN BE ALLOWED TO ¿SOAK¿ IN THE WELLS FOR ONE TO TWO DAYS BEFORE THE WELLS ARE RETURNED TO PRODUCTION. WHILE THE FIRST WELLS ARE SOAKING, STEAM INJECTION WILL BE MOVED TO THE NEXT SET OF WELLS IN THE POD. THIS PROCESS WILL CONTINUE UNTIL ALL WELLS IN THE POD HAVE BEEN STEAMED, AFTER WHICH THE CYCLE WILL BE REPEATED. SOURCE TEST RESULTS: Volatile Organic Compounds (VOC) A LOW-NOX BURNER AND FGR (VOC AS ROC) 8.5 PPMV @ 3% O2 0 U

CA-1169 BREITBURN ENERGYNEWLOVE LEASE CA 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 LEASE CA 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 PRACTICES 0.016 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 GLYCOL DEHYDRATOR REGENERATOR (STILL) VENT EMISSIONS ARE ROUTED TO AN OPEN FLARE FOR CONTROL. THE AMINE UNIT REGENERATORE EMISSIONS ARE UNCONTROLLED. 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, 2012ATTACHMENT 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 GUARANTEED. EMISSION RATES DO NOT INCORPORATE THIS POTENTIAL REDUCTION. 10 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 GUARANTEED. EMISSIONS DO NOT INCLUDE THESE POTENTIAL REDUCTIONS. 9 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 WITH TARGET OF 5.0 GRAMS NOX/BHP-HR (3.0 FOR ONE ENGINE). USE OF OXIDATION CATALYST SYSTEM. 0.8 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, 2012ATTACHMENT 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 CATALYTICREDUCTION 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 PRACTICES 0.07 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 PRACTICES 1.21 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 PRACTICES 0.32 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, 2012ATTACHMENT 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 AS NATURAL GAS 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 AS NATURAL GAS 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 AS NATURAL GAS 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/YR, BELOW THE SIGNIFICANCE LEVEL OF 40 T/YR. NOT SUBJECT TO TOP DOWN BACT. LIMIT APPLIES AT ALL POWER LEVELS. EQUIVALENT TO 52 PPM AS PROPANE 8.9 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 FLARECONTROL 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, 2012ATTACHMENT 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, 2012ATTACHMENT 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 MW SULFUR <= 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: CATERPILLAR 0.8 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 THE APPLIED FOR EMISSION FOUND IN THE APPLICATION. 1.42 LB/H 0

Attachment 1, page 8 April 3, 2012ATTACHMENT 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-T15000S. Volatile Organic Compounds (VOC) P GOOD COMBUSTION PRACTICE 0.0069 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 PROCESS 0.0052 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, WHICH UTILIZES THE LEAN-PREMIXING TECHNOLOGY TO REDUCE EMISSIONS OF NITROGEN OXIDES. Volatile Organic Compounds (VOC) P GOOD COMBUSTION PRACTICE 0.0069 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 PRACTICE 0.005 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 WEEK. THE UNIT IS SUBJECT TO THE LIMIT OF TOTAL OPERATING TIME OF 52 HOURS PER YEAR FOR MAINTENANCE. Volatile 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 COMBUSTION 0.1 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, 2012ATTACHMENT 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, 2012ATTACHMENT 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 NO1&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 DEHYDRATORREBOILER, 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 CONTROL 42.82 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, 2012ATTACHMENT 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 EMISSION LEVELS OF 0.006 LB/MMBTU REPRESENTS BACT FOR 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 NATURE OF COMPRESSOR TURBINE OPERATION, SCR WAS NOT CONSIDERED ECONOMICALLY REASONABLE OR TECHNICALLY FEASIBLE DUE TO THE NEED FOR HIGH TEMP CATALYST AND THE SMALL COMPRESSOR SIZE WHICH MEANS SMALL OVERALL TONS REDUCTION AND HIGH DOLLAR PER TON CONTROL COST COMBINED WITH UNCERTAINTY IN THE RELIABILITY OF A HIGH TEMP CATALYST. ALSO, THE REMOTE LOCATION OF THIS STATION WOULD NOT ALLOW FOR QUICK REPAIR/REPLACEMENT; RELIABILITY AND HIGH ONLINE TIME IS REQUIRED FOR THE PROJECT TO BE TECHNICALLY FEASIBLE. WATER/STEAM INJECTION WOULD NOT BE TECHNICALLY FEASIBLE DUE TO THE LACK OF AVAILABLE WATER RESOURCES AT THE LOCATION. CO WILL NOT EXCEED 50 PPM @ 15% O2. 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 PERMIT 5037A DUE TO THE REINJECTION OF THE CO2 BUT THE OTHER EMISSIONS HAVE NEVER BEEN REPRESENTED PROPERLY. 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. CALCULATED INCREASE IN NOX, CO AND VOC ARE GREATER THAN THE PSD SIGNIFICANCE LEVEL AND RECALCULATED INCREASES IN H2S AND SO2 ARE LESS THAN SIGNIFICANCE. Volatile 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, 2012ATTACHMENT 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 CONVERTERWAUKESHA 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, 2012ATTACHMENT 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 PRODUCED, THROUGHOUT THE LIFE OF THE FURNACE; NO MORE THAN 1.00 LB PM / TON OF GLASS PRODUCED, INCLUDING BOTH SOLID AND CONDENSIBLE PM; AND NO MORE THAN 1.70 LBS SO2 / TON GLASS PRODUCED. A DRY ELECTROSTATIC PRECIPITATOR (ESP) WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.15 GR/DSCF TO ACHIEVE THE NO MORE THAN 1.00 LB. PM/TON OF GLASS PRODUCED. ALSO, THE PM/PM10 PERFORMANCE LEVEL OF THIS FURNACE IS PROPOSED TO MEET THE REQUIREMENTS OF 40 CFR 63, SUBPART NNN. Volatile 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 EMISSIONS. PM/PM10 EMISSIONS WILL BE MINIMIZED BY USING ONE WET ESP WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.03 GR/DSCF ON EACH OF THE TWO FORMING SECTION EXHAUSTS AND ONE WET ESP WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.03GR/DSCF ON THE CURING/COOLING SECTION. FIRING ONLY SWEET NATURAL GAS AND IMPLEMENTING GOOD ENGINEERING PRACTICES IN THE FIBERIZERS AND THE CURING OVEN WILL MINIMIZE PRODUCTS OF COMBUSTION EMISSIONS. Volatile 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 EMISSIONS. PM/PM10 EMISSIONS WILL BE MINIMIZED BY USING ONE WET ESP WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.03 GR/DSCF ON EACH OF THE TWO FORMING SECTION EXHAUSTS AND ONE WET ESP WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.03GR/DSCF ON THE CURING/COOLING SECTION. FIRING ONLY SWEET NATURAL GAS AND IMPLEMENTING GOOD ENGINEERING PRACTICES IN THE FIBERIZERS AND THE CURING OVEN WILL MINIMIZE PRODUCTS OF COMBUSTION EMISSIONS. Formaldehyde 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 NATURAL GAS AND IMPLEMENTING GOOD ENGINEERING PRACTICES; PM/PM10 EMISSIONS WILL BE MINIMIZED BY USING FOUR WET-TYPE CYCLONIC SCRUBBERS IN SERIES EACH WITH AN OUTLET GRAIN LOADING OF NO MORE THAN 0.03 GR/DSCF. Volatile 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 OPERATIONS BY IMPLEMENTING GOOD HOUSEKEEPING PROCEDURES. THE TOTAL VOC EMISSION RATE FROM THESE OPERATIONS IS LESS THAN 10 TONS PER YEAR. THE COMPANY IS NOT PROPOSING ANY ADD-ON CONTROLS FOR THESE LABELING OPERATIONS. Volatile 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 OPERATIONS BY IMPLEMENTING GOOD HOUSEKEEPING PROCEDURES. THE TOTAL VOC EMISSION RATE FROM THESE OPERATIONS IS LESS THAN 10 TONS PER YEAR. THE COMPANY IS NOT PROPOSING ANY ADD-ON CONTROLS FOR THESE LABELING OPERATIONS. Hazardous 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, 2012ATTACHMENT 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 FACILITY TX 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 TANK 0.53 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, COMBINED WITH NON-INSTRUMENTAL METHODS (SIGHT, SOUND AND SMELL), AND GOOD OPERATING PRACTICES. 0 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, 2012ATTACHMENT 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 PRACTICES 0.02 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, 2012ATTACHMENT 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 4/11/2012ATTACHMENT 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 4/11/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012ATTACHMENT 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 4/17/2012Attachment 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 4/17/2012Attachment 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 4/17/2012Attachment 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 4/17/2012Attachment 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